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{{#Wiki_filter:}} | {{#Wiki_filter:Nuclear Operating Company South Teas Procca Elecric Gcnerating Stailon PO. Box 28.9 Wdsworth, Texs 77483 September 29, 2003 NOC-AE-31659820 STI No.: 0300161 7 File No.: G20 1 OCFR50.71 (b)U. S. Nuclear Regulatory Commission Attention: | ||
Document Control Desk Washington, D.C. 20555 South Texas Project Units 1 and 2 Docket Nos.: STN 50-498; STN 50-499 Annual Financial Reports Pursuant to the requirements of 1 OCFR50.71 (b), STP Nuclear Operating Company acting on behalf of itself and for AEP Texas Central Company, the Austin Energy, City Public Service of San Antonio, and Texas Genco, LP (formerly: | |||
Reliant Energy), submits the attached current annual financial data for the South Texas Project Electric Generating Station.Should you require additional information, please contact Karen Wheaton at (361) 972-8698 or Ron Hyde at (361) 972-7992.Ron G. Hyde Supervisor, Corporate Insurance KMW Attachments: | |||
a) AEP Texas Central Company Annual Report b) AEP Texas Central Company Form 1 0-K c) Austin Energy Annual Report d) City Public Service of San Antonio Annual Report e) Texas Genco, LP Annual Report f) Texas Genco, LP Form 1 0-K g) STP Nuclear Operating Company Financial Statement pwq0)O:\HUMtANRESOURCES\INSURANCE\ANNUAL MUST DOS\2003\NRC-ANNUAL FINANCIALS (2003).DOC STP Nuclear Operating Company cc: (paper copy)NOC-AE-31659820 File No.: G20 Page 2 (electronic copy)Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011 -8064 U. S. Nuclear Regulatory Commission Attention: | |||
Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Richard A. Ratliff Bureau of Radiation Control Texas Department of Health 11 00 West 49th Street Austin, TX 78756-3189 Jeffrey Cruz U. S. Nuclear Regulatory Commission P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 A. H. Gutterman, Esquire Morgan, Lewis & Bockius LLP L. D. Blaylock City Public Service David H. Jaffe U. S. Nuclear Regulatory Commission R. L. Balcom Texas Genco, LP A. Ramirez City of Austin C. A. Johnson AEP Texas Central Company Jon C. Wood Matthews & Branscomb C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 F. H.G.R. G.R. D.S. C.RMS File Mallen, w/o Harrison, w/o Hyde, w/o Piggott, w/o Beaver N5001 N5001 N5001 N5014 N5014 N2002 AAERiICAN t ELECURJ I FP3Wly t r I r I v , I : .,-r, Ir-iiil'I i -i rwjrr I 2/'a 313/4Ic'I \ | |||
2002 -2001 C h a n g&-Net Income (Loss) (in millions) | |||
.ongoing ' -- ---~~$95.7 $1,087-, as reported'. | |||
(519) -S(l19 $971 (153.50 Earnings (Loss) Per Share *- -, --ngoing -- .-.. -S89$3.38: | |||
-(4~as reported -11 57] $3.01 (1_2 Revenues o-(in billions) | |||
-$14 6 $12.8 -i.--~Cash Dividends | |||
-$2.40 $2.40,-Year*End Clos~~~ing Stock Price 527.33 $ 43.53 -(37 Book Value'at Year-End-- | |||
$20.85 $25.547-' ~ Total Assets (in billions): | |||
*-. .$34.7 $39.3 U.S. Customers tat year-end) (in thousands)', 4,'975,. 4,930 0 Global Employment | |||
--' 22,083 -2 3,4 (4.202rportedls f (.7 per share, adjusted fbr investmnent-Value and asset smpairmenits (33 07, p;er*- share), disposition and aSSEt iniPairmrents of SEEBOARD and CitiPo'wer (134 per share) sustainedean Ings improvement initiative restrncrurng costs ($0. 16 per share), asset impairments of Texas plants ($0.08 per share) and other items (10.04 per share), offset by~ a gain on disposition of Texas REPs ($0.23 per sharte), produces ongoing earigs of $2.89 peshae 201rpred earnings of $3.01 per share. adjuste for merger costs ($0.05 per share), neofo oso Pipe Line-related Enron purchase obligations | |||
($0.08 per share), Severance accruals ($9.08 per share), nonre--curring adjustment | |||
~~for taxes other than PIT, ($0.04 per share), disposition andwrt-onf assets -($0.01 -_per share) and an-extraordinary loss from discontinuance of regulatiyacontn firgene&ration in certain, stares ($0. 16 per share), offset by. the cumulative effect ofSA 3ransitoajumet(05) pdu es'': -ongoing earnwg of $3.38 per shae .-- ..Thsdisso inldsfradloigsaeet ihin the mening of Section 2lEof the Secursies--- Exchangze Act of. 1934. These forward-looking statemnents reflect assumptions and involve a number of risks: aduncertainties. | |||
Amiong the factors, both foreign and domestic, that could cause, acnual results to differ materiallyfrom forwvard-looking statements are: electric-load andl customer growth;, abnormnal weather ri-coditions; aiva-ilable sources -of and prices kii 6oal'and gas;_ availability ofgenerating capacity; risks related &to energy trading and contrctiont under contract; the speedl and degree to which comeiinisitoued | |||
-- to our power generation business; the stiuceure and timing of a compedtitive market~ for 'electricity and its imat on prices; the abili ty to recover net regulitory assets,'other stranded costs and implementation coats-in c'onnection'with deregulation of generation in certain states; thetirniing of the im-pl'einmntstiois of AEP-'s '-resructurng plan, new legislation and government regulations; the ability to suiccessfully control costs; the ----success.o e business ventures;: | |||
international developments affectinm u oeg netet; h economic clitnAlre and growthi in our service and trading 'territories,' | |||
both dlomestic and fiorerign; th'e ability --of the, compansy to comply, with, and to successfly. | |||
c aln~reenvironmental regultions and tosuc- T cessfulfly litigate claims that the comjpn iltdteCta n rAc;inflsti6iary rns litigation con- --cerniuig _AEP'smn'erger wihCSW; changes in electricity and gas miia et prices' n neetrts lcutos in foreign currency exchange rates, and other risks and unforescen events. ---. | |||
4 | |||
==Dear Fellow Shareholders:== | |||
ast year was extremely | |||
-difficult for AEP. Due to a variety of factors, our earn-ings fell dramatically, as did our stock price. We deeply regret that our performance was far below our goals and your expectations. | |||
In response to the negative developments in 2002, we are taking decisive steps to strengthen our bal-ance sheet and put the company back on track for value growth. We remain dedicated to providing low-cost electricity, superior customer service and an attractive return to investors. | |||
A look back: Disappointing results Our utility operations performed reasonably well in 2002 despite rising costs, but the withering of wholesale markets in the U.S. and abroad cut into earnings from our wholesale operations. | |||
As I'm sure you're aware, the wholesale arena -including power generation, associated assets and related marketing activity -had been highly profitable for us the past couple of years.AEP's ongoing earnings totaled $2.89 per share in 2002 compared with $3.38 in 2001. As-reported earnings were negative $1.57 per share, down from $3.01 the previous year.-r. Q mu. Writing down the value of poorly performing investments contributed to charges of approximately | |||
$1.5 billion for 2002. Some of these write-offs, such as those related to telecommu-nications assets, were anticipated. | |||
Others, such as a $415 million charge related to our generation assets in the United Kingdom, were not. We also incurred an equity reduction of nearly$600 million because of lost value in our pension plan assets. While the latter event lowered the equity on our balance sheet, the other items also reduced the earnings on our income statement. | |||
On the positive side, despite last year's very tough market, we strengthened our balance sheet by $2 billion. We did it by selling non-core assets and issuing additional common stock and equity units. In 2002 we completed the sale of SEEBOARD, a regional electric company in the UK, and CitiPower, an Australian electricity provider. | |||
AEP's first visit to the equity market in 20 years occurred last spring.Cash proceeds of approximately | |||
$1.1 billion from thei asset sales and $990 million from the issuance of common stock and equity units were used to pay down debt.We did not attain our capitalization goal for 2002 of 45 percent equity and 55 percent debt but we expect t o-make significant progress this year. 2002 Sharehb Our long-term goal is 50 percent to 55 percent debt.A look ahead: Focus on the basics In 2003, we will focus on the basics. We are returning to a more traditional model of a regulated utility with a small commercial group dedicated to maximizing the value of .our generation fleet, which is the largest in the United States.S&P Electric A Currently, we think AEPs traditional utility Utlity Index business 1will perform at roughly the same ............... | |||
level as last year and the wholesale business will have a somewhat weaker year. We project 2003 ongoing earnings in the range of $2.20 to $2.40 per share, including the dilution from additional equity issued in this year's older Return executive management will not be paid 0 this year. In addition, we expect to pare our-5 capital expenditures forecast for this year by to $200 million, to $1.5 billion..,i,:* -15: I .;I......EP CL cE: E-c q: _CA: E0:E-E o --o a si::;.w:¢: 0..X.,-.T :0 E f: first quarter.* O Our decision to recommend a reduction in the quarterly dividend of about 40 percent......... | |||
-25 E: to our Board of Directors came after consid--30 erable analysis andw as painful but neces-sary. Reducing the dividend to a quarterly rate of 35 cents per share, starting with the.40 : J, 0 Vsecond quarter, will result im annual cash S&P lndex ;savings of $340 million. This will imrnmedi-............. | |||
ately improve retained earnings and create free cash flow to boost liquidity and pay down debt. We believe the dividend will still have significant value and produce an attractive yield.We began shedding assets to improve our balance sheet last year and anticipate that process will accelerate in--2003. Non-core assets are the most likely candidates for divestment. | |||
This will be an orderly disposition. | |||
Proceeds-will go toward debt reduction. | |||
----Our liquidity position is strong. We have $3.5 billion available in cash and credit facilities, and we had $1.2 billion in cash at the, end of last year. During 2003, we expect free cash flow of approximately | |||
$130 million after i .i : .: :: i 0 E -: ..,:: i:: E i : -: E -i i~ ~ ~ ~ ......E .....-i .E dividends are paid.- -In 2003, we aim for year-end capitalization consistent with a strong&BBB rating. We will continue to seek To bolster our balance sheet, we plan to lower costs,.. reduce the quarterly dividend, dispose of additional non-core assets, maintain our liquidity and current lines of credit,'and maximize cash flow.A company-wide cost reduction program should result in sustainable net savings in operations and maintenance costs of approximately | |||
$60 millhon when compared with 2002 actual expenditures, and more than $300 million when compared with previously projected 2003 expendi-tures. We reduced our work force by approximately 1,300 positions. | |||
Based on 2002 performance, bonuses for senior opportunities for further debt reduction and to work with the rating agencies to ensure we're addressing their concerns.:.: | |||
With deregulation at a standstill in much of our service area,.we are re-evaluating our corporate separation initiative. | |||
The legal separation of our regulated and unregulated businesses is provided for in Texas and Ohio,_where generation is deregulated and customers in most areas are able to choose their electricity supplier.However, the cost savings and benefits for all customers of a company-wide separation are now uncertain. | |||
We are exploring these issues with our regulators. | |||
Our intent is to comply'with restructuring legislation in the states that provide for a legal separation and to maintain a functional: | |||
separation elsewhere.-- | |||
w 1 1-state service territory, thanks in part to increased usage by residential customers. | |||
AEP's Texas operations were a major contributor to last year's utility-related earnings improvement. | |||
Customer ::`choice was introduced in January 2002 in most-areas of our Texas service territory. | |||
AEP's obligation to supply .retail electric providers (REPs) in that state last year con-tributed $495 million to gross margin. Sale of our affiliat-ed REPs to Centrica, a leading retail energy provider, near the end of 2002 provided immediate cash proceeds of:$146 million. The transaction includes an arrangement through 2006 that allows AEP. to share in any increased earnings opportunities that develop in the Texas retail*market, protecting us against downside exposure.Even with deregulation stalled, many of the nearly 5 mil-lion customers linked to our Wires will benefit from rate freezes in their respective states for the next severlS years.: Utility operations: | |||
Stable, predictable AEPs regulated operations generate stable, reasonably predictable revenue and earnings. | |||
They have been a steady contributor to our performance all along. The mission of our regulated business unit is to provide safe,: cost-effective and reliable service to customers. | |||
Ongoing earnings from utility operations in 2002 totaled$326 per, share, up from $39in 2001. Retail gross -margins rose $250 million in Texas, $178 million in Ohio and $91 million in other jurisdictions throughout AP's Transmission represents a significant piece of our regulated business. | |||
AEP, following Federal Energy''Regulatory Commission (FERC) guidance, continues working toward transferring functional control of its 38,000-mile transmission network to regioa transmis-sion organizations, or RTOs. -.-You may recall that AEP was among the companies deeply involved in recent years in developing a proposed for-profit RTO called the Alliance. | |||
Last spring, however, 3 FERC turned down our proposal, so we are pursuing affil-lation with PJM Interconnection for our eastern assets and the Midwest Independent System Operator in the west, 'At this point, we don't anticipate divesting our transmis-. | |||
sion assets. We project RTO-related costs of $30 million i.to $40 million in 2003. | |||
:1 0 0 0 0-c U)0 a 0.0 S S U)N C 0 N S 0 0.U U S'Li S U E Wholesale investments: | |||
Unmet expectations Our unregulated operations performed well below our projections in 2002. AEP's wholesale investments lost$45 -million or 13 cents per share. Some of these investments, such as our natural gas and barge-line holdings, contributed positively to earnings, but the UK generation we acquired in 2001 -the Fiddler's Ferry and Ferrybridge plants -posted a $59 million operating loss.The UK has proved to be a very disappointing and difficult market. The oversupply conditions worsened as the year progressed, particularly after the British gov-'ernment decided'to subsidize British Energy. The $415 million write-down of UK generation that I mentioned earlier. stems, from recent analyses showing that UK power prices won't recover to levels that will support the carrying value of the plants on our books at the original purchase price of roughly $1 billion.As I noted above, we will be looking to divest certain wholesale assets and the UK generation certainly will be considered. | |||
An even greater loss is possible in the UK in 2003. We're evaluating the best way, to reduce earnings drags and preserve shareholder value in this investment.l E Other unregulated investments not related to our whole-sale business also fired poorly and are candidates for" i-divestment. | |||
Our telecommunications business had a $36.-million operating loss. We are actively seeking buyers for this business.Energy marketing: | |||
Asset focus.Most of the output of our generating units is committed to our retail customers. | |||
The rest is marketed to other utilities and wholesale customers. | |||
Our decision to greatly scale back our energy marketing and trading operations and concentrate on' optimizing the value of our assets is reducing our risk exposure and helping to preserve our creditrratings. | |||
Net margins from trading activities declined by'$349 million last year because of our reduced activity and because earnings from trading in 2001 were exceptionally strong. C The outstanding net fair; value of trading contracts has fallen from approximately | |||
$450 million to $250 millionA:0 over the past year. The average duration of our existing:- | |||
trading book is year-end 2003 for gas and second-half 2004 for power.--0 Our risk management group continues to work closely with the trading group to ensure limits are enforced.We reduced value-at-risk limits by 50 percent last year..Environmental: | |||
Compliance and beyond::: Coal-fired generation remains AEP's mainstay. | |||
At the end of 2002, our generating capacity mix was 69 percent coal and lignite, 20 p1ercent natural gas, 8 percent nuclear and 3 percent wind, hydro and other.Use of fossilf Eels brings with it environmental expendi-'tures, but our customer prices remain among the lowest'-`in the regions where we operate.: | |||
Our ongoing program to meet federal standards to con-trol nitrogen oxide emissions'will cost an estimated | |||
;$1.3 'billion to $2 billion in capital expenditures. | |||
AEP remains a leader in policy discussions and research to address environmnental concerns. | |||
.We are actively promoting enactment of legislation to 4 .further reduce sulfur dioxide, nitrogen oxide and mercury emissions to address air quality issues' associated withL::',-'' | |||
coal-fired generation. | |||
AEP is one of the founding' members of the Chicago Climate Exchange' the first voluntary pilot program for trading greenhouse gas emission credits.We've committed to reducing our greenhouse gas emis-: sions by4 percent over the'next four years. AEP also is:: participating in a project, led by Battelle to assess ,, 0 i, 2 E i, i X , ,;~~~~~~~ | |||
.; ........................ | |||
whether deep injection of carbon dioxide into the earth is a feasible climate-change mitigation technology. | |||
.:: Commitment to improve I want to thank our employees for their hard work during: these unsettling times in the power industry. | |||
Assets are: AEP's strength, and our employees are our strongest | |||
:::: tS ..I : ... t i. A ---E.........i- | |||
----assets. Their dedication, talent and continued commit--ment to our business mission are at the heart of our plan'.~~ ~ ~ ~ ~~~~~~ .... ... .for recovery in the year ahead.::: | |||
:::- ..: -::-:: :. : Stepping up to new duties last 'year were Holly, Koep -who was named to oversee our unregulated businesses: | |||
after the departure of Eric van der Walde; nd To ..m. .....Hagan, head of our shared services organization. | |||
Tomr: succeeded Joe' Vipperman, who retired last year after more than four decades of dedicated service.Last year was indeed difficult and 2003 also holds::many challenges. | |||
But I believe the measures I have outlined will improve our performance, and we are C'committed to doing what it takes to rebuild the value of your investment. | |||
E. Lin n Draper, Jr..Chairm~an, President | |||
&Chief Executive Officer February 28, 2003....i 7:: , f iESE-E::: | |||
.E : -. -:~ ~: 7 :: ; , 0:0 a, 0 C/) | |||
2002 2001-Assets...Cash and Cash Equivalents | |||
.1224 -Energy Trading and Derivative Contracts Current ..104B ; 26 Other Current Assets:::...3,842L Property. | |||
Plant and Equipment 3ZA14 .Accumulated Depreciation and Amortization | |||
.-- 1,V3..q .... .......d.. .............. | |||
............... | |||
......... ....... ....Net Property, Plant and Equipment | |||
...2,8 V0.............. | |||
............. | |||
.............. | |||
............. | |||
......... | |||
....Regulatory Assets 2,8 Other Assets ... ..Total .... .S24.741 Capitalization and Liabilities | |||
.. .Energy.Trading and Derivative Contracts Current:~. | |||
.$1,4$17 Other Current Liabilities 8,4 ..t4 Long-Term Debt .Deferred Income Taxes and Investment Tax Credits'47 Minoity Interest in Financing Subst iday .79 Other Liabilities | |||
..34~a Total Liabilities Cumulative Preferred Stocks of Subsidiaries | |||
.14 0: Common Shareholders' Eqluity _______Total I .... 341 1 __ _E : Full disclosure | |||
'of all Capitalization Ratio 2002 2001 o fina~ncial information o .~~~~~~~~~~~~~~0.7% | |||
.0.7%is included in the. '1 Long-Term De b-t Appendix A to the .....Proxy Statement. | |||
CiShort-Term Debt.0.U ~ ~ ~ ~ ~ Minority Equity ~~~~~~~~~~~~~~~~~~~~ | |||
32.2% -49.3% 35.8% 42.8%~' referred Stock 32 F 14.4%..:~]:* | |||
17.5%: | |||
., , '- E .- , 7 -I ., -.7 11 I " I 1- : --I r --, 1 -1 , .,, P i --1: . I ...11 I E, n .. i. Revenues Expenses: Fuel and Purchased Eniergy Mainitenianceand Other Operation | |||
:. .. .:::~~::~: | |||
Non-Recoverable Merger Costs':, .:~~~~~~~~~~~............. | |||
................ | |||
..... ......Asset Impairments | |||
:;Depreciation and Amortization | |||
.Taxes Othe r Than Income Taxes Total Expenses Other.Income | |||
...Investment Value and Other.Imnpairment Losses Other Expenses...... | |||
Income Before Interest, Preferred Dividends. | |||
Minority Interest and Income Taxes Interest, Preferred Dividends and Minority Interest Income Taxes Income Before Discontinued Oprtin, xraordinary items and Cumu lative Effect Discontinued Operations | |||
-Income (Loss) (net of tax)Extraordinary Losses (net of tax):.: Discontinu'ance of Regulatory Accounting for Generation Loss on Reacquired Debt:-Cumulative Effect of Accounting Change (net of tax)Net Income (Loss)Average Number of Shares Outstanding.. | |||
Earnings Per Share: ~.. .....Income Before Discontinued Opraions,.~~~~~~~~~~~~~~~~~~~~~~~....... | |||
Extraordinary Items and Cumulative Effect..Discontinued Operationrs. | |||
Extraordinary Losses: 1.~:: .: ,w C umulIat i ve Effect Net Income (Loss)Cash Dividends Paid Per Sha're7::- | |||
TN.M.=Not Meaningful 2002 2001.S14,55 I $12,767 f-,6,307 4,944 3,710: 10 21 7 B67~~~~~~~~. | |||
.-1,377 ~ 1,243*718: 667: 13,292 10,585 445K! 335 321 -321 j 1 87-.1,66. 2 2,330 831; 867;214 ~546 21 917 (190) ~86.1 (48): (2)S (~1) I $ 971 i3~~: 322 2 85: 0:i.26 (0.16)I (¶.57r $ 3.01 S 2.4c~ $ .40...% Change: 1.7 N.m F S C)S C)C)-u 0 S M 0 0 C,)C..0 0.0 C,)0.0.0.: w.-...11 | |||
--I 7 -: I % -1 , -" 1, --., -, -I , 1, ..-_ .- --ly .-A .., -.Jll-1 , , ., -, -i -i i,, -, -1 ; 1. I I : ", 'zi , ,_, --, '_ 1 -, 1 -% I I .7 1 1 1, _; , -., t ----.1 __ --I 1- -2002 Operating Activities | |||
-: Net Income (Loss) M .591.;NtIcm Ls):f ; ::! ............. | |||
.... ..... .. ............... | |||
........ ........... ... .... .... ..Plus: Discontinued Operations Loss (income)Net Income from Continuing Operations Depreciation and Amortization' | |||
-.. .: :.Asset Impairments Investment Value and Other Impairments ,I~~~~~~~ ............ .. .. .. .. .. .. .. .. .. ........ .................... .. .... .. .Adjustmrents for Other Noncash Items and Working Capita!l (3.. AjsmnsfrOhrNnahiesa dWrigCptl. | |||
-:. , ;................ | |||
...... ........................................... | |||
I............. | |||
... .wi : Net Cash Flows from Operating Activities i.,, ~ ~ ~ ~ ~ .... ...... ...... ....-.. .. .. .. ... .. .. ... .. .. .. ... .. .. .................... | |||
Investing Activities:. | |||
Construction Expenditures (1.. .... .................. | |||
.... ....................................................................................... | |||
.......Purchase of Gas Pipe Line Purchase of UK Generation Purchase of Coal Company:.............. ........................... | |||
............................................ | |||
.......... | |||
,......PurchaseofBargingOperations: | |||
.-: F.Purchase of Wind Generation:: | |||
Proceeds from Sale of Retail Electric Providers.~~~~~~~~~~~~~~. | |||
..................................... ........Proceeds from Sale of Foreign Investments | |||
:................................ | |||
........... | |||
..................................................................,i.i., : 1 ^ di : i:-Proceeds from Sale of U.S. Generation Net Cash Flows used for Investing Activities | |||
.E .,.,.,.,.,,,,.,.,,.,,,...,.,.,,,,............... | |||
.. ..............................- --i.. ..Financing Activities | |||
*.Fnanin.Aciviie...........::. | |||
: ....... ......... | |||
......................................... | |||
............ | |||
.... ..11..-.'.....r. | |||
Issuance ofCommon Stock .:: I-ssuance of MinorityInterest | |||
........................................... | |||
.. ...... ...... ..... ...... ...... ..... ...... ... .Issuance of Equity Unit Senior Notes I~~~~~~...................I........... | |||
..... ............................... | |||
i^.......... | |||
.,,, .... ... .....Change in Long-term Debt (net)Retirement of Cumulative Preferred Stock~:;:liRetiementof~muitive~refrredtock-T .i;0i,,e.,..........I | |||
.................................................................. | |||
.............. | |||
.. fs, Change in Short-term Debt (net)-Cagihottrebne).,'' | |||
; : .0,.......... | |||
..... ............................................ | |||
......... | |||
., l......'.... | |||
Dividen'rds Paidon Coim'mon Stock .. ..> ,. ........K.! !..* -.*- *-- *--' ---- !*-- --- *'*- .*'' ---- -'5:: .................................... | |||
......... | |||
........ ........... | |||
.. ..... .. }}}. .Other::: t,.er.. .. .. ........... | |||
............ | |||
I.............. | |||
.. ....Z_. ... ....Net Cash Flows from (used for) Financing Activities Effect of Exchange Rate Changes on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents from Continuiing Operations Beginning of Period Cash and.Cas Equivalents fo otnigOeain n fPro-:. ':Net Increase (Decrease) in Cash: and Cash Equivalents from Discontinued Operations: | |||
: .5B'' -: :-; 'Cash and Cash Equivalents from DisContinued Operations | |||
-eginning of Period Cash and Cash Equivalents from Discontinued Operations | |||
-End of Period._2001 E i.e.$+fl.:0t t:,]"jft'. | |||
N s T;eq;fsi:48-T w7S,:*--oll ,.S..:...m.:.(usi54-.''' t'1' 'f ,.g,...X, ffi;' a@t.¢ si ,,,1 b', ,=.;,. : ii ! .d... N.. _D.. -i-i _z Rl k i N I N 1 n i S: W., E.r d's is i "!] l t l:' a:.>i-r0,: 0.: U,,, C3g 0: 0 0.0 E:_E u)C" C 0`.0:.a.0.: 0 L i Ul~'E 4 srr:^ :? -:* 4:..': n ;e .i-To the Shareholders and Board of Directors:: | |||
of American Electric Power Company, Inc.:-: We have audited the consolidated balance sheets of::: American Electric Power Company, Inc.,,and its subsidiaries as of December 31, 2002 and 2001, and the related consoli-dated statements of operations, common shareholders' | |||
: .E ---: -: .:E::---; :.-- i-::f i~~~~~~. ... .... .E.::EE;: | |||
-....equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. -These consolidated financial statements and our' report thereon dated February 21, 2003, expressing an unqualified opinion (which are not included herein) are included in.. .:::: -: --:- -.:: :E :: .:E.:: -.~~~~~~~. | |||
....: .E ~fiEi. .-.-... : Appendix A to the proxy statement for the 2002 annual meeting of.shareholders. | |||
The accompanying condensed~~~~~~~~~~~~~~~~~~~~~... | |||
.... .... .... .-.consolidated financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on such condensed consolidated financial statents in relation to the complete consolidad | |||
-.statements in relation to the complete consolidated | |||
;-: S The'management of American Electric Power Company,:.: | |||
Inc., is responsible for the integrity, representations and objectivity of the information in the Company's sumrmary annual report and condensed consolidated financial state-ments. The condensed consolidated financial statements are derived from the consolidated financial statements included..in Appendix A to the proxy statement, which has been prepared in conformity with generally accepted accounting | |||
* principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. | |||
The information in other sections of this summary annual report is consistent with these statements..T:::he consolidated financial statements have been audited by Deloitte & Touche LLP, from which these condensed consolidated financial statements have been derived and whose report appears on this page. The'auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported inancial condition and results of operations. | |||
Their audit includes procedures believed by them to provide reasonable | |||
,:assurance that the financial statements are free of material::: | |||
misstatement and includes an evaluation of the Company's internal control structure over financial reporting. | |||
: .: : .-: -wq -.: Chairman, President | |||
&Chief Executive Officer .Chief Financial Officer: financial statements. | |||
In our opinion, the information set forth in the accom-:-:.:: -_ _.: _ :: ._ :: .:: ..:: : : _ :: :: :::::::_ .: : ::._...... | |||
: .:: ..::. :.. ::::-::::. | |||
panying condensed consolidated balance sheets as of December 31, 2002 and 2001, and the related condensed consolidated statements of operations and of cash flows fort:-.. .--~~~~~~~~~~~~~~~~~~~~~~~..... | |||
the years then ended is fairly stated in all material respects in relation to the basic consolidated financial statements-.-'-...:s from which it has been derived.a..e: :, :1* .>B U m U.* -u a B 0 0 N, C0 0.......... ...S S J: ..~ ~ ~ ~~~~~~~~~~~ | |||
~ ..... ..-_-~~~~~~~~~~~~~~~~w | |||
..Columbus, Ohio February 21, 2003 Board of Directors: | |||
Front row letf to right Donald G.Smith, E.R. Brooks, E. Linn Draper, Jr.,John P. DesBarres, Robert W. Fri Bac row left to right.: Donald M. Carlton, William R.Howell, Linda Gillespie Stuntz, LeonardJ. | |||
Kujawa, Richard L.Sandor, Kathryn D. Sullivan .Thomas V. Shockley, 111, Lester A. Hudson, Jr.: Dr. E. Linn Draper, Jr., 61 .-Chairman, President& Chief Executive Officer: (1992) : E.R. Brooks, 65. -Retired Chairman.a | |||
& Chief Executive Officer, Central & South West Corp..Granbury, Texas (2000) .: Dr. Donald M. Carlton, 65 Retired President& Chief Exccutive Officer, Radian International, LLC.Austin, Texas (2000) .!N. .John P. DesBarres, 63 Investor/Consultante Park City, Utah : (997) LH.N.r Robert W. Fri 67: Visiting Scholar, Resources for the FutureL Washington, D.C.(1995)?7:7-m 0 0 U, 0.0 M..0 Co..0 LU 0 0C1 William R. Howell 67 Chairman Emeritus, J.C. Penney Company, Inc.Dallas, Texas (2000) .H.P Dr. Lester A. Hudson, Jr., 63 Professor of Business Strategy, Clemson University Greenville, South Carolina:':: | |||
(18)A-DJ : : i Leonard J. Kujawa, 70 International Energy Consultant Atlanta, Georgia:: (1997) D.'-Dr. Richard L Sandor, 61 Chairman & Chief Executive Officer, Environmnental Financial. | |||
Products, LLC Chcago, Illinois (2000) Dr''f~g Thomas V. Shockley, III, 57 Vice Chairran: (2000)Donald G. Smith, 67 Chairman, President& Chief Executive Officer, Roanoke Electric Steel Corp.Roanoke, Virginia (1994) N.?- -: Linda Gillespie Stuntz, 48 Partner-: Stuntz, Davis & Staffier, P.C.Washington, D.C.(1993) "- 'Committees of the Board: The chairman is listed in ().A Audit (Carlton),. | |||
:Directors and Corporate Governance (Hudson),.-.. | |||
: Executive (Draper), Finance (Stunt), H Human Resources (DesBarres), N Nuclear Oversight (Sullivan),: | |||
Policy (Fri)Dr. Kathryn D. Sullivan, 51 President | |||
& Chief Executive Officer, Center of Science & Industry Columbus, Ohio (1997) A N.r | |||
, --r 7 , -r -e, ...-, a "'. ---7 il , 4 4. 1 .I t- :, -i _- 7 -i'. -t! E i ., ... , %American Electric P-Service Corporatior | |||
---I'ow nI:.. ~:: :. ---.. : ..: .-:.L :, : .-Office of the Chairman r Front row Iet to right: Holly K. Koeppel, E. Irnn Draper, Jr., Thomas M. Hagan, Susan Tomasky, Bac row lift to right: Robert P. Powers, Henry W. Fayne, Thomas V. Shockley, III American Electri Company. Inc.E. Linn Draper, Jr.Chairman, President Chief Executive Offi Thomas V. Shocklh Vice Chairman: c Power and Dy,Il Offic ce.Lito.icer E. Unn Draper, Jr.: Chairman, President and Chief Executive Officer Thomas V. Shockley, lli:Vice Chairman and-:'H : i;Chief Operating Officer Henry W. Fayne Executive Vice President Thomas M. Hagan --Eecutive Vice President | |||
-Shared Services Holly K. Koeppel Executive Vice President Robert P. Powers Executive Vice President | |||
-Generation | |||
-117 Susan Tomasky .:- --: Executive Vice President-Pollcy, Fiance and:.Strategic Planning, and::Assistant Secretary Melinda S. Ackerman:? | |||
Senior Vice President | |||
-Human Resources Nicholas J. Ashooh Senior Vice President-Corporate Communuications J. Craig Baker.Seniomor Vice President | |||
-Regulation and Public Polic IA. Christopher Bakken, III ,,.Senior Vice President | |||
.- -'Nuclear Operations i: .: ... .li .E'':E ..... E i !-:iL i.ver;0-3 0:0:; i,0-f; -t,;.:: :: :::::::: :: : if -:::: -:- -,* :! i: i E i.: f i -. .:.f i-D:: :S.-..::: -:.:.-:00-S't.t | |||
-::::f:: ',,' i'-....t:' T-ttT, i i :000 'l::gE: :-:: if::-i E E i: ' ;'::"* ....:!g:-t,,-*: .i-:-. :i: [-... ...: -S-.E : i t! t :,.s ' ''f' ': E .f --i 0 ;$ tiE: 'i', t-;-,.,.-;fX,,,..,404 icye'': ::... -: :.iiE--T ---fiS if -ff. -:-.tt';; -- i.E .-EE.E if i:: iL iE:EE:iE:: | |||
:E-.i.:: -....: .:. i.: i....i. i: ..---:::::::: ::::: i -" ':.':: : :E-: tiEd E ;-, i:: Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer Jeffrey D. Cross Senior Vice President, General Counsel and : Assistant Secretary. | |||
Joseph Hamrock Senior Vice President: | |||
-General Services :: Dale E. Heydlauff Senior Vice President | |||
-Governmental and Environmental Affairs Michelle S. Kalnas Senior Vice President | |||
-Supiply Chain, 'Richard E. Munczinski Senior Vice Preside'nt | |||
-Corporate Planning .:-and Budgeting: | |||
Armando A. Pe a (l}Senior Vice President | |||
-Finance and Treasurer Michael W.: Rencheck .-Senior Vice President | |||
-Technical Services:: | |||
m William L Sigmon, Jr.:-: Senior Vice President | |||
-:: 0 Fossil and Hyro H.Generation | |||
-Scott N. Smith -Senior Vice President | |||
.-. : W and Chief Risk Officer:0 3 03-........ .-(-,....::.....L- | |||
-- i i t i O* iE i,, E iSE, i .:: i -:_:~Henry W. Fayne Vice President Armando A. Pe a.Treasurer Susan Tomasky Vice President, Secnr and Chief Financial Joseph M. Buonaii ,.-1 ,, , ...E Controller and..Chief Accounting 0 | |||
I i.','I I % -.I .I"" " n-, .;_ -.1 : fil, .,-,R 2-71N7-30, _,_-:,_1_Annual Meeting -The 96th annual meeting of shareholders of American Electric Power Company will be held at 9:30 a-m.Wednesday, April 23, 2003, at The Ohio State University's Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio. Admission is by ticket only. To obtain a ticket, please note the instructions in the Notice of Annual Meeting mailed to shareholders or call the Company. If you hold your shares through a broker, please bring proof of share ownership as of the record date.Shareholder Inquiries | |||
-If you have questions about your account, contact the Company's transfer agent, listed below. You should have your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the shareholder's approval or appropriate documents. | |||
Transfer Agent & Registrar EquiServe Trust Company, N.A.(formerly First Chicago Trust Company of New York)P.O. Box 43069 Providence, RI 02940-3069 Telephone Response Group: 1-800-328-6955 Internet address: www.equiserve.com Hearing Impaired #: TDD: 1-800-952-9245 Internet Access to Your Account -If you are a registered shareholder, you can access your account information through the Internet at www.equiserve.com. | |||
Information about obtaining a password is available toll-free at 1-877-843-9327. | |||
Replacement of Dividend Checks -If you do not receive your dividend check within five business days after the dividend'pay-ment date, or if your check is lost, destroyed or stolen, you should notify the transfer agent for a replacement. | |||
Lost or Stolen Stock Certificates | |||
-If your stock certificate is lost, destroyed or stolen, you should notify the transfer agent immediately so a 'stop transfer' order can be placed on the missing certificate. | |||
The transfer agent then will send you the required documents to obtain a replacement certificate. | |||
Address Changes -It is important that we have your current address on file so that you do nor become a lost shareholder. | |||
Please contact the transfer agent for address changes fbr both record and dividend mailing addresses. | |||
We also can provide automatic seasonal address changes.Stock Transfer -Please contact the transfer agent if you have questions regarding the transfer of stock and related legal requirements,. | |||
-Dividend Rei'nvestment and Direct Stock Purchase Plan -A Dividend Reinvestment and Direct Stock Purchase Plan is avail-able to all investors. | |||
It is an' economical and convenient method of purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent... i Direct Deposit of Dividends | |||
-The Company does offer electronic deposit of your dividends. | |||
Contact the transfer agent for details.Stock Held in Brokerage Account ('Street Name') -When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker's name or 'street name.' AEP does not know the identity of idivdual shareholders who hold their shares in this manner, we simply know that a broker holds a certain number of shares which'may be for any number of customers. | |||
If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any questions you may have about your account should be directed to your broker.How to Consolidate Accounts -If you want to consolidate your separate accounts into one account, you should contact the transfer agent to obtain the necessary instructions. | |||
When accounts are consolidated, it' may be necessary to reissue the stock certificates. | |||
;; C X .,. .. .-....- ' --A. ..f: .- .- ..... ... E i ! : ; A :. : .How to Eliminate Duplicate Mailings -If you want to maintain more than one account but eliminate additional mailings of annual reports, you may do so by contacting the transfer agent, indicating the names you wish to keep on the mailing list for annual reports and the names you wish to delete. This will affect only these mailings; dividend checks and proxy materials will continue to be sent to each accountI: | |||
IdE i-Stock Trading -The Company's common stock is traded princi-pally on the New York Stock Exchange under the ticker symbol.AER AEP stock has been traded on the NYSE for 54 years.Taxes on Dividends -The Company paid $2.40 in cash dividends in 2002, all of which' are taxable for federal income tax purposes.AEP has paid consecutive quarterly dividends since 1910.Shareholder Direct -An array of timely recorded messages.about AEP, including dividend and earnings information and recent news releases, is available from AEP Shareholder Direct at 1-800-551-lAEP (1237) anytime day or night. Hard copies of information can be obtained via fax or mail. Requests for annual reports, 10-K's, 10-Q's, Proxy Statements and Summary Annual I Reports should be made through Shareholder Direct.Financial Community Inquiries | |||
-Institutional investors or secunities analysts who have questions about the Company;should direct inquiries to Bette Jo Rozsa, 614-716-2840, bjrozsa@aep.com, orJulie Sloar, 614-716-2885, jsloat@aep.com; individual shareholders should contact Kathleen Kozero, : 614-716-2819, klkozero@aep.com, or April Dawson, 614-716-2591 addawson aep.com.Internet Home Page -Information about AEP, including financial documents, SEC filings, news releases and customer service information, is available on the Company's home page,:, on the Internet at www..aep.coml | |||
.Annual Report and Proxy Materials | |||
-You can receivei: future annual reports, proxy statements and proxies electronically rather than by mail; if you are'a registered holder, log on to wvww.econsent.comlaep.- | |||
If you hold your shares in street name, contact your broker.-7IEI:Ii; Cd, M E: E.Li) | |||
WA MT NO MN i ME OR I0 C.. : F:ti'S .C) N- W I-l, So WY M!VT NH NY I MA CT RI NJ[A NE NV UT MD CA co NM KS MO DE ,, , -OKDr TN NC AZ AR LA SC MS AL GA-AEP service area-; Transmission lines FL More than 42,000 megawatts of electric generating capacity, including the largest generation fleet in the U.S.-38,000 circuit miles of transmission lines 186,000 miles of distribution lines:.128 billion cubic feet of gas storage 6,400 miles of natural gas pipeline 7,000 rail cars 1,800.barges and 37 tug boats .Annual coal production capability of 10 million tons American Electric Power owns and operates more than;'42,000 megawatts of generating capacity in the United.States and select international markets and is the largest electricity generator in the U.S. AEP is also one of the largest electric utilities in the United States, with almost 5 million customrers linked to AEP's electricity transmission and distribution grid. Those customers are located in 11 states -Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio Oklahoma, Tennessee, Texas, Virginia and West Virginia. | |||
The company's distribution service area:*6covers 197,500 square miles., Outside the United States, AEP holds interests in the United Kingdom, Australia, Brazil, China, Mexico and the Pacific Regions bs i C Ohio..AEP is based in Columbus, Ohio. 4 f 0;>z -z e | |||
2002 Annual Reports American Electric Power Company, Inc.AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Audited Financial Statements and Management s Discussion and Analysis AMERICAN ELECTRIC POWER AEPh.rnfefica:s EnewTy Partner' Contents Page Glossary of Terms i Forward Looking Information iv AEP Common Stock and Dividend Information v American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Operations A-9 Consolidated Balance Sheets A-10 Consolidated Statements of Cash Flows A-12 Consolidated Statements of Common Shareholders Equity and Comprehensive Income A-13 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-14 Schedule of Consolidated Long-term Debt of Subsidiaries A-15 Index to Combined Notes to Consolidated Financial Statements A-1 6 Independent Auditors' Report A-17 Management's Responsibility A-18 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Combined Notes to Financial Statements B-8 Independent Auditors' Report B-9 AEP Texas Central Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income C-5 Consolidated Statements of Retained Earnings C-6 Consolidated Balance Sheets C-7 Consolidated Statements of Cash Flows C-9 Consolidated Statements of Capitalization C-1 0 Schedule of Long-term Debt C-1I Index to Combined Notes to Consolidated Financial Statements C-13 Independent Auditors' Report C-1 4 AEP Texas North Company Selected Financial Data D-A Management's Narrative Analysis of Results of Operations D-2 Statements of Operations and Statements of Comprehensive Income D-4 Statements of Retained Earnings D-5 Balance Sheets D-6 Statements of Cash Flows D-8 Statements of Capitalization D-9 Schedule of Long-term Debt D-1 0 Index to Combined Notes to Financial Statements D-1 1 Independent Auditors' Report D-1 2 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Discussion and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income E-5 Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-1 0 Schedule of Long-term Debt E-1 I Index to Combined Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-1 3 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Narrative Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income F-4 Consolidated Statements of Retained Earnings F-5 Consolidated Balance Sheets F-6 Consolidated Statements of Cash Flows F-8 Consolidated Statements of Capitalization F-9 Schedule of Long-term Debt F-1 0 Index to Combined Notes to Consolidated Financial Statements F-11 Independent Auditors' Report F-1 2 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data G-1 Management's Discussion and Analysis of Results of Operations G-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income G-5 Consolidated Statements of Retained Earnings G-6 Consolidated Balance Sheets G-7 Consolidated Statements of Cash Flows G-9 Consolidated Statements of Capitalization G-10 Schedule of Long-term Debt G-1I Index to Combined Notes to Consolidated Financial Statements G-12 Independent Auditors' Report G-13 Kentucky Power Company Selected Financial Data H-1 Management's Narrative Analysis of Results of Operations H-2 Statements of Income, Statements of Comprehensive Income and Statements of Retained Earnings H4 Balance Sheets H-5 Statements of Cash Flows H-7 Statements of Capitalization H-8 Schedule of Long-term Debt H-9 Index to Combined Notes to Financial Statements H-10 Independent Auditors' Report H-11 | |||
--Ohio Power Company Selected Financial Data 1-1 Management's Discussion and Analysis of Results of Operations 1-2 Statements of Income and Statements of Comprehensive Income 1-5 Statements of Retained Earnings 1-6 Balance Sheets 1-7 Statements of Cash Flows 1-9 Statements of Capitalization 1-10 Schedule of Long-term Debt 1-11 Index to Combined Notes to Financial Statements 1-12 Independent Auditors' Report 1-13 Public Service Company of Oklahoma and Subsidiary Selected Consolidated Financial Data J-1 Management's Narrative Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income J-4 Consolidated Statements of Retained Earnings J-5 Consolidated Balance Sheets J-6 Consolidated Statements of Cash Flows J-8 Consolidated Statements of Capitalization J-9 Schedule of Long-term Debt J-10 Index to Combined Notes to Consolidated Financial Statements J-1 1 Independent Auditors' Report J-1 2 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data K-1 Management's Discussion and Analysis of Results of Operations K-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income K-4 Consolidated Statements of Retained Earnings K-5 Consolidated Balance Sheets K-6 Consolidated Statements of Cash Flows K-8 Consolidated Statements of Capitalization K-9 Schedule of Long-term Debt K-1 0 Index to Combined Notes to Consolidated Financial Statements K-1 I Independent Auditors' Report K-1 2 Combined Notes to Financial Statements L-1 Registrants Combined Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters M-1 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below: Term Meaning 2004 True-up Proceeding | |||
........ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs.AEGCo .. ................... | |||
AEP Generating Company, an electric utility subsidiary of AEP.AEP .................. | |||
American Electric Power Company, Inc.AEP Consolidated | |||
.................... | |||
AEP and its majority owned consolidated subsidiaries. | |||
AEP Credit .................. | |||
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and non-affiliated domestic electric utility companies. | |||
AEP East companies | |||
............... | |||
APCo, CSPCo, I&M, KPCo and OPCo.AEPR .................. | |||
AEP Resources, Inc.AEP System or the System ....... The American Electric Power System, an integrated electric utility system, owned and operated by AEP s electric utility subsidiaries. | |||
AEPSC .................... | |||
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. | |||
AEP Power Pool .................... | |||
AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. | |||
AEP West companies | |||
............... | |||
PSO, SWEPCo, TCC and TNC.AFUDC .................... | |||
Allowance forfunds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant.Alliance RTO .. .................. | |||
Alliance Regional Transmission Organization, an ISO formed byAEP and four unaffiliated utilities (the FERC overturned earlier approvals of this RTO in December 2001).Amos Plant ................... | |||
John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.APCo ..................... | |||
Appalachian Power Company, an AEP electric utility subsidiary. | |||
Arkansas Commission | |||
............. | |||
Arkansas Public Service Commission. | |||
Buckeye .................. | |||
Buckeye Power, Inc., an unaffiliated corporation. | |||
CLECO .................. | |||
Central Louisiana Electric Company, Inc., an unaffiliated corporation. | |||
COLI .................. | |||
Corporate owned life insurance program.Cook Plant .................. | |||
The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.CPL .................... | |||
Central Power and Light Company [legal name changed to AEP Texas Central Company (TCC) effective December 2002]. See TCC.CSPCo .................... | |||
Columbus Southern Power Company, an AEP electric utility subsidiary. | |||
CSW ...... ............ | |||
Central and South West Corporation, a subsidiary of AEP (Effective January 21,2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).CSW Energy ................... | |||
CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.CSW International | |||
.................... | |||
CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States.D.C. Circuit Court .................... | |||
The United States Court of Appeals for the District of Columbia Circuit.DHMV ................... | |||
Dolet Hills Mining Venture.DOE .................. | |||
United States Department of Energy.ECOM ................... | |||
Excess Cost Over Market.ENEC .................... | |||
Expanded Net Energy Costs.EITF .................... | |||
The Financial Accounting Standards Board s Emerging Issues Task Force.ERCOT .................. | |||
The Electric Reliability Council of Texas.EWGs .................. | |||
Exempt Wholesale Generators. | |||
FASB .................. | |||
Financial Accounting Standards Board.Federal EPA .................. | |||
United States Environmental Protection Agency.i FERC ................ | |||
Federal Energy Regulatory Commission. | |||
FMB ..... ........... | |||
First Mortgage Bond.FUCOs ...... .......... | |||
Foreign Utility Companies. | |||
GAAP ..... ........... | |||
Generally Accepted Accounting Principles. | |||
I&M ................ | |||
Indiana Michigan Power Company, an AEP electric utility subsidiary. | |||
ICR ................ | |||
Interchange Cost Reconstruction. | |||
IPC .... ............ | |||
Installment Purchase Contract.IRS .... ............ | |||
Internal Revenue Service.IURC ................ | |||
Indiana Utility Regulatory Commission. | |||
ISO .... ............ | |||
Independent System Operator.Joint Stipulation | |||
.. ................ | |||
Joint Stipulation and Agreement for Settlement of APCo s WV rate proceeding. | |||
KPCo ................ | |||
Kentucky Power Company, an AEP electric utility subsidiary. | |||
KPSC ................ | |||
Kentucky Public Service Commission. | |||
KWH .................. | |||
Kilowatthour. | |||
LIG ................ | |||
Louisiana Intrastate Gas.Michigan Legislation | |||
................ | |||
The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.MISO .................. | |||
Midwest Independent System Operator (an independent operator of transmission assets in the Midwest).MLR ................ | |||
Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.Money Pool ........ ........ AEP System s Money Pool.MPSC ................ | |||
Michigan Public Service Commission. | |||
MTM ..... ........... | |||
Mark-to-Market. | |||
MTN ..... ........... | |||
Medium Term Notes.MW ................ | |||
Megawatt.MWH ..... ........... | |||
Megawatthour. | |||
NEIL ..... ........... | |||
Nuclear Electric Insurance Limited.NOx ................ | |||
Nitrogen oxide.NOx Rule ................ | |||
A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate.NP .................. | |||
Notes Payable.NRC ................ | |||
Nuclear Regulatory Commission. | |||
Ohio Act ................ | |||
The Ohio Electric Restructuring Act of 1999.Ohio EPA ................ | |||
Ohio Environmental Protection Agency.OPCo ................ | |||
Ohio Power Company, an AEP electric utility subsidiary. | |||
OVEC ................ | |||
Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.PCBs ................ | |||
Polychlorinated Biphenyls. | |||
PJM .................. | |||
Pennsylvania New Jersey Maryland regional transmission organization. | |||
PRP ................ | |||
Potentially Responsible Party.PSO ................ | |||
Public Service Company of Oklahoma, an AEP electric utility subsidiary. | |||
PUCO ................ | |||
The Public Utilities Commission of Ohio.PUCT .................. | |||
The Public Utility Commission of Texas.PUHCA ................ | |||
Public Utility Holding Company Act of 1935, as amended.PURPA ................ | |||
The Public Utility Regulatory Policies Act of 1978.RCRA .... ............ | |||
Resource Conservation and Recovery Act of 1976, as amended.Registrant Subsidiaries | |||
............. | |||
AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.REP ................ | |||
Retail Electric Provider.Rockport Plant ................ | |||
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and l&M.RTO ................ | |||
Regional Transmission Organization. | |||
ii SEC ............. | |||
Securities and Exchange Commission. | |||
SFAS .... ......... | |||
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.SFAS 71 ............... | |||
Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. | |||
SFAS 101 ............... | |||
Statement of Financial Accounting Standards No. 101, Accounting forthe Discontinuance of Application of Statement 71.SFAS 133 ............. | |||
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. | |||
SNF ............. | |||
Spent Nuclear Fuel.SPP ............... | |||
Southwest Power Pool.STP ............... | |||
South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an AEP electric utility subsidiary. | |||
STPNOC ..... ........ STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including TCC.Superfund | |||
............. | |||
The Comprehensive Environmental, Response, Compensation and Liability Act.SWEPCo ............... | |||
Southwestern Electric Power Company, an AEP electric utility subsidiary. | |||
TCC ............. | |||
AEP Texas Central Company, an AEP electric utility subsidiary | |||
[formerly known as Central Power and Light Company (CPL)].Texas Appeals Court ............. | |||
The Third District of Texas Court of Appeals.Texas Legislation | |||
.. ............. | |||
Legislation enacted in 1999 to restructure the electric utility industry in Texas.TNC ............. | |||
AEP Texas North Company, an AEP electric utility subsidiary | |||
[formerly known as West Texas Utilities Company (WTU)].Travis District Court ............. | |||
State District Court of Travis County, Texas.TVA ............... | |||
Tennessee Valley Authority. | |||
U. ............. | |||
The United Kingdom.UN ............. | |||
Unsecured Note.VaR ............... | |||
Value at Risk, a method to quantify risk exposure.Virginia SCC ............. | |||
Virginia State Corporation Commission. | |||
WV ............... | |||
West Virginia.WVPSC ............... | |||
Public Service Commission of West Virginia.WPCo ............. | |||
Wheeling Power Company, an AEP electric distribution subsidiary. | |||
WTU ............. | |||
West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective December 2002]. See TNC.Yorkshire | |||
............... | |||
Yorkshire Electricity Group pic, a U.K. regional electricity company owned jointly by AEP and New Century Energies until April 2001.Zimmer Plant ............. | |||
William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary. | |||
iii FORWARD LOOKING INFORMATION These reports made byAEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21 E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. | |||
Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:* Electric load and customer growth.* Abnormal weather conditions. | |||
.Available sources and costs of fuels.* Availability of generating capacity.* The speed and degree to which competition is introduced to our service territories. | |||
* The ability to recover stranded costs in connection with possible/proposed deregulation. | |||
* New legislation and government regulation. | |||
* Oversight and/or investigation of the energy sector or its participants. | |||
* The ability of AEP to successfully control its costs.* The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile.* International and country-specific developments affecting AEP's foreign investments including the disposition of any current foreign investments and potential additional foreign investments. | |||
.The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.* Inflationary trends.* Electricity and gas market prices.* Interest rates.* Liquidity in the banking, capital and wholesale power markets..Actions of rating agencies.* Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. | |||
.Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.iv AEP Common Stock and Dividend Information The quarterly high and low sales prices and the quarter-end closing price for AEP common stock and the cash dividends paid per share are shown in the following table: Quarter-end Quarter Ended High Low Closing Price Dividend March 2002 $47.08 $39.70 $46.09 $0.60 June 2002 48.80 39.00 40.02 0.60 September 2002 40.37 22.74 28.51 0.60 December2002 30.55 15.10 27.33 0.60 March 2001 $48.10 $39.25 $47.00 $0.60 June 2001 51.20 45.10 46.17 0.60 September 2001 48.90 41.50 43.23 0.60 December 2001 46.95 39.70 43.53 0.60 AEP common stock is traded principally on the New York Stock Exchange. | |||
At December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003 management recommended thatthe Company reduce dividends by approximately 40% after payment of the March 2003 dividend which was approved by the Company s Board of Directors at the current level of $0.60 per share.v AMERICAN ELECTRIC POWER COMPANY, INC.AND SUBSIDIARY COMPANIES AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES selected consolidated Financial Data Year Ended December 31, 2002 2001 2000 1999 1998 OPERATIONS STATEMENTS DATA (in millions): | |||
Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080 operating Income 1,263 2,182 1,774 2,061 2,046 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 21 917 180 869 859 Discontinued operations Income (Loss) (190) 86 122 117 116 Extraordinary Losses -(50) (35) (14) _Cumulative Effect of Accounting change Gain (Loss) (350) 18 ---Net Income (Loss) (519) 971 267 972 975 December 31. 2002 2001 2000 1999 1998 BALANCE SHEET DATA (in millions): | |||
Property, Plant and Equipment | |||
$37,857 $37,414 $34,895 $33,930 $32,400 Accumulated Depreciation and Amortization 16.173 15.310 14.899 14.266 13.374 Net Property, Plant and Equipment | |||
$22,104 $19,996 S1 5664 Total Assets $34,741 $39,297 $46,633 $35,296 $33,418 Common shareholders' Equity 7,064 8,229 8,054 8,673 8,452 Cumulative Preferred Stocks of Subsidiaries* | |||
145 156 161 182 350 Trust Preferred securities 321 321 334 335 335 Long-term Debt* 10,496 9,505 8,980 9,471 9,215 Obligations under capital Leases* 228 451 614 610 539 Year Ended December 31. 2002 2001 2000 1999 1998 COMMON STOCK DATA: Earnings per Common share: Before Discontinued operations, Extraordinary Items and cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70 Discontinued Operations (0.57) 0.26 0.38 0.36 0.36 Extraordinary Losses -(0.16) (0.11) (0.04) -cumulative Effect of Accounting change (1.06) 0.06 ---Earnings (Loss) Per share (1.5) $3.1 $0-83 $ 3.03 $_3.0 Average Number of shares Outstanding (in millions) 332 322 322 321 318 Market Price Range: High $ 48.80 $51.20 $48-15/16 | |||
$48-3/16 $53-5/16 Low 15.10 39.25 25-15/16 30-9/16 42-1/16 Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16 cash Dividends on Common** $ 2.40 $2.40 S2.40 $2.40 $2.40 Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%Book value per share $20.85 $25.54 $25.01 $26.96 $26.46*Including portion due within one year. Long-term Debt includes Equity unit senior Notes.**Based on AEP historical dividend rate. See "Common stock and Dividend Information (on page v) regarding the potential reduction of future dividends. | |||
A-1 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Managements Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S. We provide generation, transmission and distribution service to almost five million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. | |||
We have a vast portfolio of assets including: | |||
* 38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in our market areas.4,000 megawatts of generating capacity in the U.K., a countrywhich is currently experiencing excess generation capacity* 38,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S.* 186,000 miles of distribution lines that support delivery of electricity to our customers premises a Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity)* 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of gas storage facilities Business Strategy We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets. We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business.Through our utility operations focus, we intend to be the energy and low cost generation provider of choice. We have ample generation to meet our customers needs.We have a cost advantage resulting from AEP s long tradition of designing, building and operating efficient power plants and delivery networks. | |||
Our customers continue to show top quartile level of satisfaction. | |||
We provide safe and reliable sources of energy.Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. | |||
Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors. | |||
We are addressing many challenges in our unregulated business. | |||
We have already substantially reduced our trading activities. | |||
We have written down the value of several investments to reflect deterioration in market conditions. | |||
We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy. | |||
We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling. | |||
Transition rules for Michigan and Virginia do not require legal separation. | |||
Deregulation is no longer an expectation in the foreseeable future in the other states where we operate.Our strategy for the core business of utility operations is to:.Maintain moderate but steady earnings growth* Maximize value of transmission assets and protect our revenue stream in an RTO membership environment | |||
* Continue process improvement to maintain distribution service quality while, at the same time, further enhancing financial performance | |||
* Optimize generation assets through increased availability and sale of A-2 excess capacity Manage the regulatory process to maximize retention of earnings improvement while providing fair and reasonable rates to our customers We remain very focused on credit quality and liquidity as discussed in greater detail later in this report.We are committed to continually evaluating the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and sustainable shareholder value. Any investment dispositions could affect future results of operations, cash flows and possibly financial condition. | |||
2002 Overview 2002 was a year of rapid and dramatic change for the energy industry, including AEP, as the wholesale energy market quickly shrank and many of its participants exited or significantly limited future trading activity.Investors lost confidence in corporate America and the economy stalled. Investors demand for stability, predictable cash flows, earnings, and financial strength have replaced their demand for rapid growth.Our wholesale business did not perform well.We had significant losses in options trading in the first half of the year and new investments performed well below our expectations. | |||
We focused on financial strength by:* Issuing approximately | |||
$1 billion in common stock and equity units.Retiring debt of approximately | |||
$3 billion through the sale of two foreign retail utility companies in the U.K.(SEEBOARD) and Australia (CitiPower) | |||
* Establishing a cash liquidity reserve of$1 billion at year-end See Financing Activity in Managements Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters in section M for an overview of all changes to capital structure. | |||
We also focused on:* Implementing an enterprise-wide risk management system* Completing a cost reduction initiative which we expect to result in sustainable net annual savings of more than $200 million beginning in 2003* Eliminating or reducing future capital requirements associated with non-core assets We have redirected our business strategy by:* Scaling back trading activities to focus principally on supporting our core assets* Selling our Texas retail business.Proposing the sale of a significant portion of the Texas unregulated generation assets Outlook for 2003 We remain focused on the fundamental earnings power of our utility operations, and we are committed to strengthening our balance sheet. Our strategy for achieving these goals is well planned:* First, we will continue to identify opportunities to reduce our operations and maintenance expense.* Second, we will find opportunities to reduce capital expenditures. | |||
* Third, management recommended a 40% reduction in the common stock dividend beginning in the second quarter to a quarterly rate of $0.35 per share. This will result in annual cash savings of approximately | |||
$340 million and should improve our retained earnings as well as create free cash flow to improve liquidity and pay-down outstanding debt.* Fourth, we plan to evaluate and, where appropriate, dispose of non-core assets. Proceeds from these sales will be used to reduce debt..Fifth, we will continue to evaluate the potential for issuing additional equity to further strengthen our balance sheet and maintain credit quality.We remain committed to being a low cost provider of electricity, to serving our A-3 customers with excellence and to providing an attractive return to investors. | |||
We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets.Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters. We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors. | |||
Results of Operations In 2002, AEP s principal operating business segments and their major activities were:* Wholesale: | |||
o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity trans-mission o Domestic electricity distri-bution* Other Investments o Energy Services Net Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased | |||
$896 million or 98% to $21 million in 2002 from $917 million in 2001. The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. | |||
In 2002, the Company s Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3).Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP s wholesale marketing business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. The effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron s bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.Our wholesale business has been affected by a slowing economy. Wholesale energy margins and energy use by industrial customers declined in 2002 and 2001.Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO.Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues in 2002 and 2001.Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001.A-4 Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be more volatile. | |||
See 'Market Risks section for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. | |||
Revenues Increase AEP s total revenues increased 14% in 2002 and 15% in 2001. The following table shows the components of revenues: For The Year Ended December 31 2002 2001 2000 (in millions)WHOLESALE: | |||
Residential | |||
$ 3,713 commercial 2,156 Industrial 1,903 other Retail customers 385 Electricity Marketing (net) 2,227 unrealized MTM Income-Electric 136 other 1,397 Less: Transmission and Distribution Revenues Assigned to Energy Delivery* | |||
(3.551)wholesale Electric 8.366 S 3,553 2,328 2,388 S 3,511 2,249 2,444 419 414 802 1,073 210 38 632 837 has had a major effect on the volume of wholesale power marketing especially in the short-term market.The increase in 2002 in wholesale revenues resulted from a 27% increase in trading volume associated with Wholesale Electricity which was offset by a continuing decrease in gross margins which began in the fourth quarter of 2001, and an increase in residential sales as a result of favorable weather conditions in the third quarter 2002.In addition OtherWholesale electric revenues increased due to the mid-year 2001 acquisition of barging and coal mining operations as well as the recognition of revenues for generation projects completed for third parties. The increase in 2002 Wholesale Gas revenues resulted from a full year of HPL operations compared to a partial year from our acquisition date in July 2001, offset by a decrease in the results from financial trading and MTM unrealized losses.Other Investments revenue decreased in 2002 due to the elimination of factoring of accounts receivable of an unaffiliated utility.Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. | |||
Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 1).Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in 2001. This decrease was due to the economic slow down which began in late 2001. Sales to residential customers rose 5%due to weather related demand in 2002. The economic slow down reduced demand and wholesale prices especially in the latter part of 2001.i (3.356) (3.174)6,97 7,392 Gas Marketing (net) 3,021 2,274 unrealized MTM Income (Loss)-Gas (399) 47 wholesale Gas 2.622 2.321 TOTAL WHOLESALE 10.988 9.297 310 132 442 7,834 DOMESTIC ELECTRICITY DELIVERY: Transmi ssi on Distribution TOTAL DOMESTIC ELECTRICITY DELIVERY OTHER INVESTMENTS 922 1,029 1,009 2.629 2,327 2.165 3.551 3,356 3,174 16 114 105 TOTAL REVENUES S14,5m 11.77 ,*Certain revenues in the wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.The level of electricity transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC s introduction of a greater degree of competition into the wholesale energy market A-5 I Ooeratina ExDenses Increase Changes in the components of operating expenses were as follows: Inc Fr Amour Fuel and Purchased Energy: Electricity | |||
$ 959 Gas 404 Maintenance and other operation 303 Non-recoverable Merger Costs (11)Asset Impairments 867 Depreciation and Amortization 134 Taxes other Than Income Taxes 51 Total:rease (Decrease) tom Previous Year 2002 200.(in millions)it % Amount %43.7 S(1,275)(36.7) 14.7 2,339 570.5 8.2 i (52.4)N.M.228 6.5 (182) (89.7)CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected, merger costs declined in 2001 and 2002 after the merger was consummated. | |||
In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling $1.4 billion (consisting of approximately, $866.6 million related to asset impairments, $321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included: 2002 Pre-Tax Estimated Loss (in millions)10.8 152 13.9 7.6 (16) (2.3)25.6 51.246 13.3 The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. | |||
Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001. The return to service of the Cook Plants two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation. | |||
The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001.The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full years expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. | |||
The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001.Maintenance and Other Operation expense rose in 2001 mainly as a result of additional traders incentive compensation and accruals for severance costs related to corporate restructuring. | |||
With the consummation of the merger with Asset Impairments Held for sale Asset Impairments Held and used Investment value Losses S 483.1 651.4 291.9 Total Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations. | |||
The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service.Depreciation and Amortization expense increased in 2001 primarily as a result of the A-6 commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and WestVirginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in Property, Plant and Equipment. | |||
Taxes OtherThan IncomeTaxes increased in 2002 due to a full year of state excise taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in Texas partly offset by the effect of Texas one-time 2001 assessments and decreased gross Texas receipts taxes due to deregulation. | |||
Interest. | |||
Preferred Stock Dividends, Minority Interest The decrease in Interest in 2002 was primarily due to a reduction in short-term interest rates and lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates offset in part by an increased amount of long-term debt outstanding. | |||
Interest expense decreased 15% in 2001 due to the effect of interest paid to the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.Minority Interest in Finance Subsidiary increased substantially in 2002 because the distributions to minority interest were in effect for the entire year. In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest. | |||
The minority interest was only in effect during the last four months of 2001.Other Income/Other Expenses This increase was primarily caused by an increase in equity earnings due to acquisitions of $63 million and a $73 million gain from the sale of a generating plant (see Note 1). Other Expenses increased by $110 million or 143%in 2001 due to costs to exit air transportation, fiber optic and Datapult businesses (see Note 1).Income Taxes The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book income offset by the tax effects of the sale of foreign operations. | |||
Although pre-tax book income increased considerably in 2001, Income Taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000.Extraordinary Losses and Cumulative Effect The loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change on January 1, 2002.In 2001 we recorded an extraordinary loss of$48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. | |||
The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after-tax extraordinary loss of $35 million.New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark-to-market certain fuel supply contracts that qualify as financial derivatives. | |||
The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a Cumulative Effect of Accounting Change.Other Income increased by $110 million or 33% in 2002 due to the sale of AEP S retail electric providers in Texas and due to non-operational revenue (see Note 1). Other Expenses increased | |||
$134 million or 72% in 2002 due to non-operational expenses (see Note 1).Other Income increased | |||
$240 million in 2001.A-7 mI Discontinued Operations The operations shown below were discontinued or held for sale in 2002 (See Note 12). Results of operations including impairment losses, net of tax, of these businesses have been reclassified: | |||
Company 2002 2001 2000 (in millions)SEEBOARD 5 96 S 88 5 99 CitiPower (123) (6) 17 Pushan (7) 4 7 Eastex (156) -(1)90) 5 86 S12 Reclassification Balance sheet amounts have been restated to reflect our change in accounting policy regarding certain assets and liabilities related to forward physical and financial transactions (see "Reclassification discussion Note 1.)Based upon AEP s legal rights of offset, physical and financial contracts were netted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not netted in 1998 amounts as the impact is not material.A-8 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Operations (in millions -except per share amounts)Year Ended December 31.2002 2001 2000 REVENUES: wholesale Electricity S 8,366 S 6,976 $ 7,392 wholesale Gas 2,622 2,321 442 Domestic Electricity Delivery 3,551 3,356 3,174 other Investment 16 114 105 TOTAL REVENUES 14,555 12.767 11.113 EXPENSES: Fuel and Purchased Energy: Electricity 3,154 2,195 3,470 Gas 3.153 2,749 410 TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880 Maintenance and other operation 4,013 3,710 3,482 Non-recoverable Merger Costs 10 21 203 Asset Impairments 867 --Depreciation and Amortization 1,377 1,243 1,091 Taxes other Than Income Taxes 718 667 683 TOTAL EXPENSES 13.292 10,585 9,339 OPERATING INCOME 1,263 2,182 1,774 OTHER INCOME 445 335 95 LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 --LESS: OTHER EXPENSES 321 187 77 LESS: INTEREST 785 844 999 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 11 10 11 MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -INCOME BEFORE INCOME TAXES 235 1,463 782 INCOME TAXES 214 546 602 INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT 21 917 180 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122 EXTRAORDINARY LOSSES (NET OF TAX): DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION | |||
-(48) (35)LOSS ON REACQUIRED DEBT -(2) -CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -NET INCOME (LOSS) S 51) $ 971 $ 267 AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322 EARNINGS-(LOSS) | |||
PER SHARE: Income Before Discontinued operations, Extraordinary Items and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56 Discontinued Operations (0.57) 0.26 0.38 Extraordinary Losses -(0.16) (0.11)Cumulative Effect of Accounting change (1.06) 0.06 Earnings (Loss) Per share (Basic and Diluted) I$(1.5) L3.01 $ 0.83 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 J24 See Notes to Consolidated Financial Statements beginning on page L-1.A-9 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (in millions -except share data)December 31.2002 2001 ASSETS CURRENT ASSETS: Cash and cash Equivalents | |||
$ 1,213 $ 224 Accounts Receivable: | |||
customers 466 343 Miscellaneous 1,394 1,365 Allowance for uncollectible Accounts C119) (69)Fuel, Materials and Supplies 1,166 1,037 Energy Trading and Derivative Contracts 1,046 2,125 other 935 639 TOTAL CURRENT ASSETS 6,101 5,664 PROPERTY, PLANT AND EQUIPMENT: | |||
Electric: Production 17,031 17,054 Transmission 5,882 5,764 Distribution 9,573 9,309 Other (including gas and coal mining assets and nuclear fuel) 3,965 4,272 Construction work in Progress 1,406 1,015 Total Property, Plant and Equipment 37,857 37,414 Accumulated Depreciation and Amortization 16,173 15,310 NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104 REGULATORY ASSETS 2,688 3,162 SECURITIZED TRANSITION ASSETS 735 -INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633 ASSETS HELD FOR SALE 247 721 ASSETS OF DISCONTINUED OPERATIONS | |||
-3,954 GOODWILL 396 392 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795 OTHER ASSETS 1.783 1,872 TOTAL ASSETS $34,741 See Notes to Consolidated Financia1 Statements beginning on page L-1.A-10 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31, 2002 2001 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: | |||
Accounts Payable $ 2,042 S 1,914 short-term Debt 3,164 4,011 Long-term Debt Due within one Year* 1,633 1,095 Energy Trading and Derivative Contracts 1,147 1,877 other 1.804 1.924 TOTAL CURRENT LIABILITIES 9.790 10,821 LONG-TERM DEBT* 8.487V 8.410 EQUITY UNIT SENIOR NOTES 376 -LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603 DEFERRED INCOME TAXES 3.916 4.500 DEFERRED INVESTMENT TAX CREDITS 455 491 DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819 DEFERRED GAIN ON SALE AND LEASEBACK | |||
-ROCKPORT PLANT UNIT 2 185 194 OTHER NONCURRENT LIABILITIES 1.903 1.334 LIABILITIES HELD FOR SALE 91 87 LIABILITIES OF DISCONTINUED OPERATIONS | |||
-2.582 COMMITMENTS AND CONTINGENCIES (Note 9)CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH 321 321 SUBSIDIARIES MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* | |||
145 156 COMMON SHAREHOLDERS' EQUITY: Common Stock-Par value $6.50: 2002 2001 shares Authorized. | |||
.600,000,000 600,000,000 shares Issued. ...347,835,212 331,234,997 (8,999,992 shares were held in treasury at December 31, 2002 and 2001) 2,261 2,153 Paid-in Capital 3,413 2,906 Accumulated other Comprehensive Income (Loss) (609) (126)Retained Earnings 1,999 3,296 TOTAL COMMON SHAREHOLDERS' EQUITY 7.064 8,229 TOTAL LIABILITIES AND SHAREHOLDERS EQUITY $ $39297*See Accompanying schedules. | |||
See Notes to Consolidated Financial Statements beginning on page L-1.A-11 I AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated statements of cash Flows (in millions)Year Ended December 31.2002 2001 2000 OPERATING ACTIVITIES: | |||
Net Income (Loss) $ (519) S 971 $ 267 Plus: Discontinued operations 540 (86) (122)Net income from Continuing operations 21 885 145 Adjustments for Noncash Items: Asset Impairments, Investment value and other Impairments 1,188 --Depreciation and Amortization 1,403 1,277 1,152 Deferred Investment Tax Credits (31) (29) (36)Deferred Income Taxes (66) 157 (190)Amortization of operating Expenses and Carrying charges 40 40 48 cumulative Effect of Accounting Change (18) -Equity Earnings of Yorkshire Electricity Group plc -(44)Extraordinary Loss 50 35 Deferred costs under Fuel clause Mechanisms (31) 340 (449)Mark-to-Market of Energy Trading Contracts 263 (257) (170)Miscellaneous Accrued Expenses 30 (384) 217 changes in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net) (152) 1,766 (1,530)Fuel, Materials and Supplies (127) (78) 149 Accrued Revenues (283) 35 (71)Accounts Payable 52 (478) 1,292 Taxes Accrued (216) (147) 171 Payment of Disputed Tax and Interest Related to COLI --319 change in other Assets (177) (239) (283)change in other Liabilities (237) (161) 386 Net cash Flows From Operating Activities 1,677 2,759 1.141 INVESTING ACTIVITIES: | |||
Construction Expenditures (1,722) (1,654) (1,468)Purchase of Gas Pipe Line -(727) -Purchase of U.K. Generation | |||
-(943) -Purchase of coal Company -(101) -Purchase of Barging Operations | |||
-(266) -Purchase of wind Generation | |||
-(175) -Proceeds from Sale of Retail Electric Providers 146 --Proceeds from sale of Foreign Investments 1,117 383 -Proceeds from Sale of U.S. Generation | |||
-265 -other 37 (42) (18)Net Cash FlowS used For Investing Activities (422) (3.260) (1.486)FINANCING ACTIVITIES: | |||
Issuance of Common stock 656 11 14 Issuance of Minority Interest -744 -Issuance of Long-term Debt 2,893 2,863 878 Issuance of Equity unit Senior Notes 334 -Retirement of Cumulative Preferred stock (10) (5) (21)Retirement of Long-term Debt (2,514) (1,570) (1,303)change in short-term Debt (net) (829) (790) 1,328 Dividends Paid on Common stock (793) (773) (805)Dividends on Minority Interest in subsidiary | |||
-(5) -Net Cash Flows From (used for) Financing Activities (263) 475 91 Effect of Exchange Rate Changes on Cash (3) (1) 30 Net Increase (Decrease) in cash and cash Equivalents 989 (27) (224)cash and cash Equivalents from Continuing operations Beginning of Period 224 251 475 Cash and cash Equivalents from Continuing Operations | |||
-End of Period $L213 L 224 S 251.Net Increase (Decrease) in Cash and cash Equivalents from Discontinued operations | |||
$ (100) $ 17 $ (17)Cash and cash Equivalents from Discontinued operations Beginning of Period 108 91 108 Cash and Cash Equivalents from Discontinued operations End of Period $ 8A08 $ 91 See Notes to consolidated Financial Statements beginning on page L-1.A-12 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equitv and Comprehensive Income (in millions)DECEMBER 31, 1999 Issuances cash Dividends Declared Other comprehensive Income: Other Comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment Reclassification Adjustment For LOSS Included in Net Income Net Income Total Comprehensive Income DECEMBER 31, 2000 Issuances cash Dividends Declared other comprehensive Income: Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability Net Income Total Comprehensive Income DECEMBER 31, 2001 Issuances cash Dividends Declared Other Com prehensive Income: Other comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability unrealized Loss on securities Available For Sale Net Income (Loss)Total comprehensive Income DECEMBER 31, 2002 Common stock shares Amount 331 $2,149-3 331 331 17$2, 152 1$2,153 108 Paid-In Capi tal$2,898 11 6 S2,915 9 (18)S2,906 568 (61)S 3.13 Retained Earnings S3,630 (805)(2)267$3,090 (773)8 971$3,296 (793)15 (519)1S9M Accumulated other comprehensive Income (Loss)$ (4)(119)20 S (103)(14)(3)(6)S (126)117 (13)(585)(2)sff)Total$8,673 14 (805)4 7,886 (119)20 267 168$8,054 10 (773)(10)7,281 (14)(3)(6)971 948$8,229 676 (793)(4 )(163)117 (13)(585)(2)(519)(1.002)MA See Notes to Consolidated Financial statements beginning on page L-1.A-13 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31. 2002 Call Price per Shares Shares Amount (In share(a) Authorized(b) | |||
Outstandinatf) | |||
Millions)Not subject to Mandatory Redemption: | |||
4.00% -5.00% S102-$110 1,525,903 608,150 $ 61 Subject to Mandatory Redemption: | |||
5.90% -5.92% (c) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 51 Total subject to Mandatory Redemption (c) 84 Total Preferred stock 1145 December 31. 2001 Call Price per Shares shares Amount (In share(a) Authorized(b) | |||
Outstandino(f) | |||
Millions)Not subject to Mandatory Redemption: | |||
4.00% -5.00% S102-S110 1,525,903 614,608 $ 61 subject to Mandatory Redemption: | |||
5.90% -5.92% Cc) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 100,000 10 Total subject to Mandatory Redemption (c) 95 Total Preferred Stock S156 NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. | |||
The involuntary liquidation preference is S100 per share for all outstanding shares.(b) AS of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and 7,713,501 shares of $100,$25 and no par value preferred stock, respectively, that were authorized but unissued.(c) shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements. | |||
The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.(d) Not callable prior to 2003, after that the call price is $100 per share plus accrued dividends.(e) with sinking fund.(f) The number of shares of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares in 2001 and 209,563 shares in 2000.A-14 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries Maturity weighted Average Interest Rate December 31. 2002 Interest Rates 2002 at December 31.2001 December 31.2002 2001 (in millions)FIRST MORTGAGE BONDS (a)2002 -2004 2005 -2008 2022-2025 INSTALLMENT PURCHASE CONTRACTS (b)2002-2009 2011-2030 NOTES PAYABLE (c)2002-2021 SENIOR UNSECURED NOTES 2002 -2005 2006-2012 2032-2038 JUNIOR DEBENTURES 2025-2038 SECURITIZATION BONDS 2003-2016 OTHER LONG-TERM DEBT (d)Unamortized Discount (net)Total Long-term Debt outstanding Less Portion Due Within One Year Long-term Portion EQUITY UNIT SENIOR NOTES 2007 6.87%6.90%7.66%4.62%5.83%5.54%5.53%5.91%6.64%7.90%5.40%5.75%6.00%-7.85% | |||
6.20%-8%6.875%-8.7% | |||
3.75%-7.70% | |||
1.35%-8.20% | |||
3.732%-9.60% | |||
2.12%-7.45% | |||
4.31%-6.91% | |||
6.00%-7-3/8% | |||
7.60%-8.72% | |||
6.00%-7.85% | |||
6.20%-8%6-7/8%-8.80% | |||
1.80%-7.70% | |||
1.55%-8.20% | |||
4.048%-9.60% | |||
2.31%-7.45% | |||
6.125%-6.91% | |||
7.20%-7-3/8% | |||
7.60%-8.72% | |||
$ 648 463 773 396 1,284 520 1,834 2,295 690 205 797 247 (32)10.120 1 633 S 1,246 699 850 446 1,234 217 1,910 1,727 340 618 258 (40)9, 505 1.095 L 8410 3.54%-6.25% | |||
5.75%S-376 NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.(b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. | |||
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. | |||
At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. | |||
variable rates generally relate to specified short-term interest rates.(d) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 9 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. | |||
Long-term debt outstanding at December 31, 2002 (includes Equity Unit senior Notes) is payable as follows: (in millions)2003 2004 2005 2006 2007 Later Years Unamortized Discount Total S 1,633 824 993 1, 611 1,081 4.386 10,528 32£10,9 A-15 AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Combined Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Goodwill and other Intangible Assets Merger Nuclear Plant Restart Rate Matters Effects of Regulation customer Choice and Industry Restructuring Commitments and contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans stock-Based compensation Business Segments Risk Management, Financial Instruments And Derivatives Income Taxes Basic and Diluted Earnings Per share Supplementary Information Power and Distribution Projects Leases Lines of credit and sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Minority Interest in Finance subsidiary Equity units Subsequent Events (unaudited) combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 5 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 15 Note 16 Note 17 Note 18 Note 19 Note 20 Note 21 Note 22 Note 23 Note 24 Note 25 Note 26 Note 27 Note 30 A-16 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Companys management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted ouraudits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 3 to the consolidated financial statements, the Company adopted SFAS 142, 'Goodwill and Other Intangible Assets, effective January 1, 2002.As discussed in Note 13 to the consolidated financial statements, the Company recorded certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002./s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 A-17 L_MANAGEMENTS RESPONSIBILITY The management of American Electric Power Company, Inc. has prepared the financial statements and schedules herein and is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. | |||
These statements have been prepared in conformity with accounting principles generally accepted in the United States of America, using informed estimates where appropriate, to reflect the Company s financial condition and results of operations. | |||
The information in other sections of the annual report is consistent with these statements. | |||
The Company s Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Companys established internal control structure over financial reporting. | |||
The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP -independent auditors and the Companys internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. | |||
The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the previous page.The auditors provide an objective, independent review as to management s discharge of its responsibilities insofar as they relate to the fairness of the Company s reported financial condition and results of operations. | |||
Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Companys internal control structure over financial reporting. | |||
A-18 AEP GENERATING COMPANY AEP GENERATING COMPANY Selected Financial Data INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant Year Ended December 31.2002 2001 2000 1999 1998 (in thousands) | |||
$213,281 $227,548 $228,516 $217,189 $224,146 207,152 220.571 220,092 211,849 215,415 6,129 6,977 8,424 5,340 8,731 3,681 3,484 3,429 3,659 3,364 2,258 2,586 3.869 2.804 3.149 ,$L52 $ 77875 $ ,94 $6J195 $ Ai December 31.2002 2001 2000 1999 1998 (in thousands) | |||
$652,213 358.174$648,254 337,151$-3-1-,10$642,302 315.566$36,736$640,093 295.065 ,$345,028$636,460 277. 855 Total Assets$349,729 $361,41 $374,602 A U $403 892 Common stock and Paid-in capital Retained Earnings Total Common shareholder's Equity$ 24,434 18.163$ 4259$ 24,434 13.76$ 3-8,19-5$ 24,434 9,722$ 30,235 3.673$ 36,235 2,770$ 900 Long-term Debt (a)Total Capitalization And Liabilities S_4i8QZ $4,793 $ 44,808 $ 48 44,79 UAJTZ9 $36 1 ,41 $374,602 $98 4 $403 1892 (a) Inc7uding portion due within one year.B-1 AEP GENERATING COMPANY Management s Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. | |||
Operating Expenses Decrease Operating Expenses decreased 6% as follows: Operating Revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved long-term unit power agreements. | |||
Under the terms of its unit power agreement, l&M will purchase all of AEGCo's Rockport capacity unless it is sold to other utilities. | |||
A unit power agreement between AEGCo and KPCo expires in 2004.The KPCo unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. | |||
The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. | |||
Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. | |||
In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. | |||
Results of Operations (dollars in thousands) | |||
._ _ .._ ._ .., _ _ _ _ _ _ _ _ _Increase (Decrease) | |||
From Previous Year Amount %$(13,723) | |||
(13)1,899 17 565 6 137 1 Fuel other operation Maintenance Depreciation Taxes other Than Taxes Income Taxes Total Income (976)(1.321)S (3,41)(23)(46)(6)The decrease in Fuel expense reflects a decrease in generation and lower average fuel costs.Other Operation expense increased due to increased costs for employee benefits and property insurance. | |||
The increase in Maintenance expense can be attributed to shorter duration of maintenance outages for boiler inspection and repair in 2001.Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and personal property taxes reflecting a favorable change in the law which lowered the tax for Rockport Plant.Net Income decreased | |||
$323,000 or 4% as a result of limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant.The decrease in Income Taxes attributable to operations is primarily due to a decrease in pre-tax operating income and a change in estimate for state income tax accruals.Operating Revenues Decrease The decrease in Operating Revenues of$14,267,000 or 6% reflects a decrease in recoverable expenses, primarily fuel.B-2 AEP GENERATING COMPANY Statements of Income OPERATING REVENUES OPERATING EXPENSES: Fuel Rent -Rockport Plant Unit 2 other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Year Ended December 31.2002 2001 2000 (in thousands) | |||
$213.281 $227.548 $228,516 TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDITS INTEREST CHARGES NET INCOME 89,105 68,283 12,924 9,418 22,560 3,281 1.581 207,152 6,129 343 198 3,536 2.258.$ -752 102,828 68,283 11,025 8,853 22,423 4,257 2.902 220. 571 6,977 30 16 3,470 2.586$_zl875 102,978 68,283 10,295 9,616 22,162 3,854 2.904 220.092 8,424 6 17 3,440 3.869$ 7L984 Statements of Retained Earnings RETAINED EARNINGS JANUARY 1 NET INCOME CASH DIVIDENDS DECLARED RETAINED EARNINGS DECEMBER 31 See Notes to Financia7 Statements beginning on page L-1.Year Ended December 31.2002 2001 2000 (in thousands) | |||
$13,761 $ 9,722 $3,673 7,552 7,875 7,984 3 150 3.836 1.935 18&-63 $13 ,761 $4X7 B-3 AEP GENERATING COMPANY Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production | |||
$637,095 $638,297 General 4,728 3,012 Construction work in Progress 10.390 6.945 Total Electric Utility Plant 652,213 648,254 Accumulated Depreciation 358,174 337.151 NET ELECTRIC UTILITY PLANT 294,039 311.103 OTHER PROPERTY AND INVESTMENTS 119 119 CURRENT ASSETS: cash and cash Equivalents | |||
-983 Accounts Receivable: | |||
Affiliated Companies 18,454 22,344 Miscellaneous | |||
-147 Fuel 20,260 15,243 Materials and supplies 4,913 4,480 Prepayments | |||
-244 TOTAL CURRENT ASSETS 43.627 43.441 REGULATORY ASSETS 4.970 5.207 DEFERRED CHARGES 6,974 1.471 TOTAL ASSETS S3A 4 29 $6134 see Notes to Financial Statements beginning on page L-1.B4 AEP GENERATING COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common stock Par value $1,000: Authorized and outstanding 1,000 Shares $ 1,000 $ 1,000 Paid-in capital 23,434 23,434 Retained Earnings 18163 13761 Total Common shareholder s Equity 42,597 38,195 Long-term Debt 44.802 44,793 TOTAL CAPITALIZATION 87.399 82.988 OTHER NONCURRENT LIABILITIES 301 76 CURRENT LIABILITIES: | |||
Advances from Affiliates 28,034 32,049 Accounts Payable: General 26 7,582 Affiliated Companies 15,907 1,654 Taxes Accrued 2,327 4,777 Rent Accrued Rockport Plant Unit 2 4,963 4,963 other 1.111 3.48 TOTAL CURRENT LIABILITIES 52.368 54.506 DEFERRED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 111,046 116.617 REGULATORY LIABILITIES: | |||
Deferred Investment Tax credits 52,943 56,304 Amounts Due to Customers for Income Taxes 16.670 22.725 TOTAL REGULATORY LIABILITIES 69.613 79.029 DEFERRED INCOME TAXES 29.002 27,975 DEFERRED CREDITS -150 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES | |||
$349,729 $M1,341I See Notes to Financia7 statements beginning on page L-1.B-5 AEP GENERATING COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation Deferred Income Taxes Deferred Investment Tax Credits Amortization of Deferred Gain on sale and Leaseback | |||
-Rockport Plant Unit 2 Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable Fuel, Materials and supplies Accounts Payable Taxes Accrued other Assets other Liabilities Net Cash Flows From operating Activities | |||
$ 7,552 S 7,875 $ 7,984 22,560 (5,028)(3,361)(5,571)4,037 (5,450)6,697 (2,450)(5,211)(2.295)11,480 22,423 (6,224)(3,414)(5,571)1,224 (4,738)(4, 597)(216)(569)(1.244)4,949 22,162 (5,842)(3,396)(5,571)1,392 6,486 (13,157)708 1,636 (404)11. 998 INVESTING ACTIVITIES Construction Expenditures FINANCING ACTIVITIES: | |||
Return of Capital to Parent Company change in short-term Debt (net)Change in Advances From Affiliates (net)Dividends Paid Net Cash Flows From (Used For)Financing Activities (5,298)(4,01-5)(3,150)(7.165)(6,868)3,981 (3.836)145 (5,190)(5,801)(24,700)28,068 (1.935)(4,368)Net Increase (Decrease) in cash and cash Equivalents Cash and cash Equivalents January 1 cash and cash Equivalents December 31 supplemental Disclosure: | |||
Cash Paid for interest net of capitalized amounts was and for income taxes was $7,884,000, $8,597,000 and respectively. | |||
(983)983$~ _(1,774)2,757$ 98 2,440 317$2,019,000, $1,509,000 and $3,531,000 | |||
$6,820,000 in 2002, 2001 and 2000, See Notes to Financial Statements beginning on page L-1.B-6 11, AEP GENERATING COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) | |||
COMMON STOCK EQUITY (a) $42.597 $38.195 LONG-TERM DEBT Installment Purchase Contracts City of Rockport (b)series Due Date 1995 A, 2025 (c) 22,500 22,500 1995 B, 2025 (c) 22,500 22,500 unamortized Discount (198) (207)TOTAL LONG-TERM DEBT 44.802 44,793 TOTAL CAPITALIZATION | |||
$87399 29 (a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There were no other material transactions affecting Common stock and Paid-in Capital in 2002, 2001 and 2000.(b) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant.(C) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006.See Notes to Financia 7 Statements beginning on page L-1.B-7 AEP GENERATING COMPANY Index to Combined Notes to Financial Statements The notes to AEGCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to AEGCo. The combined footnotes begin on page L-1.significant Accounting Policies Effects of Regulation Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 7 Note 9 Note 10 Note 11 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 B-8 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of AEP Generating Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 B-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES | |||
=AEP TEXAS CENTRAL COMPANY AND Selected Consolidated Financial Data SUBSIDIARIES 2002 Year Ended December 31.2001 2000 (in thousands) 1999 INCOME STATEMENTS DATA: operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements Gain (Loss) on Reacquired Preferred Stock$1,690,493 1.296.760 393,733 8,079 125.871 275,941 275,941$1,738,837 1,443.106 295,731 5,324 116.268 184,787 (2.509)182,278$1,770,402 1.463.304 307,098 7,235 124,766 189,567 189,567$1,482,475 1.188.490 293,985 8,113 114 380 187,718 (5 517)182,201 6,931 1998$1,406,117 1 123.330 282, 787 760 122.036 161,511 161,511 6,901 241 242 241 4 (2.763)Earnings Applicable To Common stock$_275704 1$_182L 06$ 172.507 L$_ 15-461Q Year Ended December 31.2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation And Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$5,625,736 2.405.492$320 -244$5'536P438 | |||
$ 187,898 (73,160)986.396$1- 1O1t 13A$ 5,942-2001$5,769,707 2.446.027$ 573,903 826,197$1,420QlQQ 2000 (in thousands) | |||
$5,592,444 2.297,189$ 573,904 792,219$ 5,951 1999$5,511,894 2.247,225$ 573,904 758.894-$-I 33-,79$5.95 1998$5,336,191 2.072.686$4,735,_ff | |||
$ 573,904 734. 387$1 1QWLZX CPL Obli ated, Mandatori 1y Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior subordinated Debentures of CPL Long-term Debt (a)Total capitalization And Liabilities | |||
$-13-6 Z 5-SI136 25Q$148,500$1,454,559 | |||
$154,5I41$5,467,01$4,735,656 (a) Including portion due within one year.C-1 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Managrement s Discussion and Analvsis of Results of Operations AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TCC s behalf byAEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TCC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TCC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TCC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. | |||
As a result of the formation of the affiliated REP, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. | |||
The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC s sales as described below under"Results of Operations. | |||
In December 2002, AEP sold the affiliated REP to an unrelated third party who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Affiliates. | |||
Subsequent to the sale, transactions with the REP were classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income increased | |||
$94 million or 51 % primarily due to $262 million of revenues associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas which resulted in the loss of customers and reduced prices (see Note 8).In 2001, Income Before Extraordinary Item decreased | |||
$5 million or 3%, primarily resulting from a settlement of Texas municipal franchise fees and increased Maintenance expenses.Changes in Operating Revenues Increase (Decrease) | |||
From Previ ous Year (dollars in millions)2002 2001 Amount % Amount whol esal e El ectri ci ty*Energy Delivery*Sales to AEP S (1, 096.4) (90) S(29.9) (2)81.4 17 (5.6) (1)Affiliates 966.7 N.M. 4.0 11 Total 5(8.) (3) 5 31. 5) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful In 2002, Wholesale Electricity revenues decreased as a result of the elimination of TCCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins offset in part by the interchange cost reconstruction C-2 (ICR) adjustments (see Note 6). In 2001, the decrease in Wholesale Electricity revenues was primarily attributable to unfavorable wholesale power marketing and trading conditions. | |||
In 2002, Sales to AEP Affiliates revenue increased primarily due to increased revenues from the newly created affiliated REP.Although TCC sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue. Revenues for 2002 included $262 million of revenues, associated with recognition of stranded costs in Texas (see Note 8). Energy Delivery revenue also included revenues received for securitized assets beginning in 2002 (see Note 8).Chances in Operatinc ExDenses based on the current spot market price.Changes in natural gas prices affect TCC s fuel expense; however, they generally did not impact results of operations in 2001 and 2000 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.In 2002, the increase in Wholesale Electricity Purchased Power expense is due to higher MWH purchases from the market where we could purchase power at prices lowerthan our cost to produce. ICR adjustments also had the effect of increasing Wholesale Electricity Purchased Power expense and decreasing AEP Affiliates Purchased Power expense in 2002 (see Note 6).In 2001, Purchased Power increased overall largely due to higher natural gas prices.Although gas prices declined in 2001, they were higher during the first half of 2001 when TCC was making most of its purchases. | |||
In 2002, Other Operation expense decreased due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses.Increase (Decrease) | |||
From Previous Year A Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreci ati on And Amortization Taxes other Than Income Taxes Income Taxes Total V((dollars in millions) | |||
In 2002, Maintenance expense decreased 2002 2001 due to two scheduled | |||
'18 month interval mount % Amount % refueling outages for STP during 2001 that increased Maintenance expense above the:246.2) (50) SC58.8) C11) 2002 and 2000 levels. Also contributing to the decrease in 2002, and the increase in 83.5 65 C16.2) (11) 2001, was an increase in Maintenance 83.5* 65 (16.2) (l ) expense for scheduled major overhauls of (35.3) (60) 26.0 80 four power plants in 2001.(17.1) (5) 1.7 1-7 1 -I -tO'.i.) L.+/-+/-J +/-U. I IO In 2002, the increase in Depreciation and Amortization is attributable to the amortization 45.8 27 (10.4) (6) of regulatory assets that were securitized in 4. 6 5 14.4 19 the first quarter of 2002, offset by the 26.1 23 12.4 12 elimination of excess earnings expense in.46) (10) -A) C') 2002 under Texas Restructuring Legislation (see Note 8).la In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of fuel and decreased generation. | |||
The decrease in Fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. TCC used natural gas as fuel for 32% of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax, due to deregulation. | |||
In 2001, Taxes Other Than Income Taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees, and a new tax levied by the C-3 PUCT, the Texas System Benefit Fund Assessment. | |||
In 2002, the increase in Income Taxes is due to an increase in pre-tax income offset by changes in timing between book/tax accounting differences in state income taxes.In 2001 the increase in Income Tax expense is primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income.Other Changes In 2002, Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the energy related construction projects included in Nonoperating Income increased | |||
$34 million and $15 million in 2002 and 2001. The expenses associated with these projects included in Nonoperating Expenses increased$32 million and $14 million in 2002 and 2001.current cost to generate electricity, TCC proposed in September 2002 to "inactivate various, high-cost gas fired generating facilities. | |||
In the third quarter 2002, TCC recorded an impairment charge of approximately | |||
$95.6 million (pre-tax) related to these plants and recorded approximately | |||
$4.0 million (pre-tax) for severance charges.Both of these charges were deferred and recorded in RegulatoryAssets Designated for or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 8). In the fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional plant impairments, fuel inventory and materials and supplies, and an additional | |||
$1.5 million pre-tax charge was recorded related to severance charges (see Note 13) related to the Inactivated plants. The entire $23.1 million was also deferred and recorded in Regulatory Assets Designated for or Subject to Securitization. | |||
In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax non-operating income.In 2002, Interest Charges increased primarily due to higher levels of outstanding debt (see TCC s schedule of Long-term Debt and Consolidated Statements of Capitalization for further information). | |||
In 2001, the decrease in interest charges was attributable to lower average interest rates associated with short-term and long-term debt.Extraordinary Loss The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas.Impairment As a result of TCC s recent abilityto purchase electricity at a significantly lower price than its C-4 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP A ffiliates TOTAL OPERATING REVENUES$ 127,502 554,547 1.008.444 1.690.493 OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES 245,834 211,358 23,406 304,094 63,392 214,162 95,500 139.014 1. 296, 760$1,223,893 473,182 41.762 1. 738. 837 492,057 127,816 58,641 321,227 71,212 168,341 90,916 112.896 1.443.106$1,253,836 478,814 37.752 1.770.402 550,903 144,021 32,591 319,539 60,528 178,786 76,477 100.459 1.463. 304 OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)393,733 53,141 41,910 3,152 295,731 22,552 17,626 (398)307,098 5,830 3,668 (5,073)INTEREST CHARGES 125. 871 116.268 124,766 INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567 EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001)NET INCOME 275,941 (2.509)182,278 242 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS GAIN ON REACQUIRED PREFERRED STOCK 241 241 4 EARNINGS APPLICABLE TO COMMON STOCK$ -18Z-16 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 (in thousands) | |||
$182,278 2000$189,567 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME$275,941 (36)(73,124)$18 2- dl1 S1W2,WA The common stock of TCC is owned by a wholly owned subsidiary of AEP.See Notes to Financia7 statements beginning on page L-1.C-5 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31.2002 2001 2000 (in thousands) | |||
BEGINNING OF PERIOD $826,197 $792,219 $758,894 NET INCOME 275,941 182,278 189,567 DEDUCTIONS (ADDITIONS): | |||
Capital stock Gains (4) --Cash Dividends Declared: Common stock 115,505 148,057 156,000 Preferred stock 241 242 241 other -1 1 BALANCE AT END OF PERIOD 26 $ 6197 $792,219 The common stock of TCc is owned by a wholly owned subsidiary of AEP.see Notes to Financial statements beginning on page L-1.C-6 | |||
--AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Nuclear Fuel Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS SECURITIZED TRANSITION ASSETS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
General Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued Utility Revenues Energy Trading and Derivative Contracts Prepayments and other current Assets TOTAL CURRENT ASSETS REGULATORY ASSETS REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION NUCLEAR DECOMMISSIONING TRUST FUND DEFERRED CHARGES TOTAL ASSETS See Notes to Financial Statements beginning on page L-1.$2,903,942 698,964 1,296,731 258,386 200,947 266.766 5,625,736 2.405.492 3.220.244 3.977 734. 591 4.392 85,420 113,543 121,324 (346)32,563 51,593 27,150 22,493 2.133 455.873 458. 552 336.444 98.474 43,891 Sig56 E438$3,169,421 663,655 1,279,037 241,137 169,075 5,769,707 2.446,027 3. 323.680 47,950 28 039 10,909 38,459 6,249 (186)38,690 55,475 34,480 2.742 186 818 226. 812 959,294 98.600 21.837$4,9303 C-7 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock $25 Par Value: Authorized 12,000,000 shares outstanding 2,211,678 shares at December 31, 2002 6,755,535 shares at December 31, 2001 Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock CPL obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of CPL Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
short-term Debt Affiliates Long-term Debt Due within one Year Advances from Affiliates (net)Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$ 55,292 132,606 (73,160)986 396 1,101,134 5,942 136,250 1,209.434 2.452.760 74.572 650,000 229,131 126,711 72,199 36,242 666 24,791 51,205 19,811 36. 698 1.247.454 1.261.252 117.686 1,713 201.001 S5,356 A438$ 168,888 405,015 826.197 1,400,100 5,952 136,250 988.768 2,531.070 10.905 265,000 354,277 65,307 49,301 26,744 83,512 23,715 40,987 18,076 926.919 1,163.795 122.892 17,675 119.774$4 1 9,83A3D C-8 | |||
--l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income Adjustments to Reconcile Net Income to Net cash Flows from Operating Activities: | |||
Depreciation and Amortization Extraordinary Loss on Reacquired Debt Deferred Income Taxes Deferred Investment Tax credits Mark-toMarket Energy Trading and Derivative Contracts change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Interest Accrued Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission coordination Agreement settlement Texas wholesale Clawback (see Note 7)change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From Sales of Property and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt change in short-term Debt Affiliate (Net)Retirement of Common stock Retirement of Preferred stock Retirement of Long-term Debt change in Advances from Affiliates (net)special Deposit for Reacquisition of Long-term Debt Dividends Paid on Common stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities | |||
$275,941 $182,278 $189,567 214,162 113,655 (5,206)(1,558)(189,999)(4,899)27,490 (27,150)(6,167)(58,721)16,455 (262,000)(534)56.024 147.493 (151,645)143 (151. 502)797,335 650,000 (386,005)(6)(639,492)(227,566)(115, 505)(241)78.520 168,341 2,509 (72,568)(5,208)(12,048)52,862 (18,215)(2,502)(55, 311)27,986 179,866 10,767 11,163 469,920 (193,732)(354)(194.086)260,162 (475,606)84,565 (148,057)(242)(279,178)178,786 16,263 (5,207)8,191 (32,902)8,680 11,494 45,873 14,405 (96,872)15,519 589 12 .243 366,629 (199,484)(199.484)149,248 (151,440)(52,446)50,000 (156,000)(249)(160.887)Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1 Cash and cash Equivalents December 31 74,511 10.8909 (3,344)14.253 SLQ 3Q9 6,258 7.995 illw53 supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and for income taxes. was$95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and 2000,respectively. | |||
see Notes to Financial statements beginning on page L-1.C-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
S1.10o.134 S1.400.100 COMMON SHAREHOLDER S EQUITY (a)PREFERRED STOCK 3,035,000 authorized shares, 5100 par value Not Subject to Mandatory Redemption: | |||
call Price -December 31, Number of shares Redeemed series 2002 Year Ended December 31. Dec 2002 2001 2000 Shares outstanding | |||
:ember 31. 2002 4.00% S105.75 100 --41,938 4,194 4.20% 103.75 ---17,476 1.748 Total Preferred stock 5.942 TRUST PREFERRED SECURITIES: | |||
TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of TCC, 8.00%due April 30, 2037 136.250 LONG-TERM (See schedule of Long-term Debt): First Mortgage Bonds 152,353 Securitization Bonds (a) 796,635 Installment Purchase Contracts 489, 577 Senior unsecured Notes -Less Portion Due within One year (229.131)Long-term Debt Excluding Portion Due within one Year 1.209.434 TOTAL CAPITALIZATION (a) In February 2002, TCC issued securitization bonds. S386 million of the proceeds 4,543,857 shares of common stock.See Notes to Financial Statements beginning on page L-1.4,204 1,748 5.952 136. 2 50 614,200 489,568 150,000 (265.000)988. 768 was used to retire C-1 0 i -AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
December 31, 2002 2001 (in thousands) | |||
% Rate Due 7.25 2004 7.50 2002 6-7/8 2003 7-1/8 2008 7.50 2023 6-5/8 2005 Total October 1 December 1 February 1 February 1 April 1 July 1 S 27,400 16,418 18,581 17,996 71. 958$100,000 115,000 49,200 75,000 75,000 200 000 ikQu Q% Rate Due Matagorda County Navigation District, Texas: 6.00 2028 July 1 6-1/8 2030 May 1 3.75 2030(a) May 1 4.00 2030(a) May 1 4.55 2029(a) Nov .Guadalupe-Blanco River Authority District, Texas: (b) 2015 November 1 Red River Authority District, Texas:$120,265 60,000 111,700 50,000 100,635 S120,265 60,000 111,700 50,000 100,635 First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Securitization Bonds outstanding were as follows: 40,890 40,890 Final Payment Maturity Rate Date Date 3.54 1/15/2005 1/15/2007 5.01 1/15/2008 1/15/2010 5.56 1/15/2010 1/15/2012 5.96 7/15/2013 7/15/2015 6.25 1/15/2016 1/15/2017 unamortized Discount Total December 31.2002 2001 (i~nthousands) 6.00 2020 June 1 6,330 6,330 unamortized Discount (243) (252)Total S4O9,577 (a)installment Purchase contract provides for bonds to be tendered in 2003 for 3.75% and 4.00% series and in 2006 for 4.55% series.Therefore, these installment purchase contracts have been classified for payments in those years.(b) A floating interest rate is determined monthly. The rate on December 31, 2002 was 1.7%.Under the terms of the installment purchase contracts, TCC is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: S128,950 154,507 107,094 214,927 191,857 (700)5796>6i5$In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 2002 February 22 Cc)Total December 31.2002 2001 (in thousands) | |||
$ -S150.000 S -$150.AlOO (c) A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.56%.C-11 At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 229,131 75,951 121,937 152,900 52,729 806.860 1,439,508 (943)51,438,56 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of TCC.C-12 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to TCC s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to TCC. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Merger Rate Matters Effects of Regulation customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Asset Impairment and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 C-1 3 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas Central Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Companyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31,2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 C-14 | |||
-J al AEP TEXAS NORTH COMPANY AEP TEXAS NORTH COMPANY Selected Financial Data 2002 Year Ended December 2001 2000 (in thousands) 31 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income (Loss) Before Extraordinary Item Extraordinary Loss Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$ 450,740 442.869 7,871 (703)20,6845 (13,677)(13,677)104$556,458 523.068 33,390 2,195 23, 275 12,310 12,310 104$571,064 518.723 52,341 (1,675)23,216 27,450 27,450 104 1999$445,709 391.910 53,799 2,488 24,420 31,867 (5.461)26,406 104 1998$424,953 365,677 59,276 2,712 24.263 37,725 37,725 104$ 37,621$ (13.781)S 34-6 S 26,302 2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric utility Plant Total Assets Common stock and Paid-in Capital Accumulated other Comprehensive Income (LosS)Retained Earnings Total Common Shareholder's Equity$1,201,747 521.792 S 679,955$ 877,175$ 139,565 (30,763)71.942$1&80,744 2001$1,260,872 546,162$ 714,710$ 139,565 105.970$_241S53-5 December 31.2000 (in thousands) | |||
$1,229,339 515,041$ 714,298 51,087. 504$ 139,565 122,588$_262 153 1999$1,182,544 495.847 5 686,697$ 861,205$ 139,565 113,242 S_252 s807 1998$1,146,582 473.503$ 673,079$,819,446 S 139,565 114.940 S 254,505 Cumulative Preferred stock: Not subject to Mandatory Redemption S 2,367 Long-term Debt (a) $ 132,50 Total Capitalization And Liabilities S 877L21Z5 S 255,967 255.7$S_22 _N S 6 8 L&6t4875 S1.087.iOA 5 8612,05 S _819A446 (a) Including portion due within one year.D-1 AEP TEXAS NORTH COMPANY Manaaement s Narrative Analysis of Results of ODerations AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TNC s behalf byAEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory. | |||
Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TNC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TNC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TNC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. | |||
As a result of the formation of the affiliated REP, effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. | |||
The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC s sales as described below under"Results of Operations. | |||
In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale, during 2002, sales to the affiliated REP were classified as Sales to AEP Affiliates. | |||
Subsequent to the sale, transactions with the REP will be classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income decreased | |||
$26.0 million or 211 % primarily due to a $38.1 million long-lived asset impairment charge ($24.8 million net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a$4.7 million impairment charge ($3.1 million net of tax) related to the abandonment of a wind-powered generation facility (see Note 13).Changes in Operatina Revenues Increase (Decrease) | |||
From Previous Year (in millions) h wholesale Electricity* | |||
Energy Delivery*sales to AEP S(231. 7)(95.7)(63)(57)Affiliates 221.7 N.M.Total ()05.7) (19)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful Wholesale Electricity revenues decreased as a result of the elimination of TNCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins, partially offset by the ICR adjustments (see Note 6).D-2 Sales to AEP Affiliates increased primarily due to increased revenues from the newly created affiliated REP. Although TNC sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue.Changes in Operating Expenses Increase (Decrease) | |||
From Previous Year (in millions) | |||
%Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total S(76.7)10.0 (19 .1)(6.3)42.9 (7.1)(5.8)(18.1)gun 2)(43)14 (34)(6)N.M.(14)(21)N.M.(15)electricity at a significantly lower price than its current cost to generate electricity, TNC proposed in September 2002 to Inactivate various, high-cost gas fired generating facilities. | |||
TNC recorded an impairment charge in the third quarter 2002 of approximately | |||
$34.2 million related to these plants, which was recorded in Asset Impairments expense. In the fourth quarter 2002, an additional asset impairments charge of $3.9 million was also recorded in connection with these plants, along with a$4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, a $1.2 million charge associated with fuel inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (recorded in Other Operations) was recorded in the fourth quarter of 2002 related to the"inactivated plants.Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation and the elimination of regulatory asset amortization that ended in 2001.The decrease in Taxes Other Than Income Taxes is primarily a result of one time 2001 assessments and a decrease in the gross receipts tax due to deregulation. | |||
The decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the impairment of various generating facilities. | |||
Other Changes Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the aforementioned energy related construction projects included in Nonoperating Income increased | |||
$45.5 million in 2002. The expenses associated with these projects included in Nonoperating Expenses increased | |||
$43.0 million in 2002.Interest Charges declined primarily due to lower interest rates.N.M. = Not Meaningful Fuel expense decreased due to a decrease in the average unit cost of fuel and decreased generation required due to decreased energy sales. TNC used natural gas as fuel for 42%of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect TNC s fuel expense;however, they generally did not impact results of operations in 2001 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.The net decline in total Purchased Power expense in 2002 was mainly due to both reduced MWHs purchased and reduced prices, partially offset by ICR adjustments (see Note 6).Other Operation expense decreased slightly in 2002 due to lower factoring and transmission expenses, offset in part by a$1.4 million write-down of material and supply inventory associated with the impaired plants.As a result of TNC s recent ability to purchase D-3 it, AEP TEXAS NORTH COMPANY Statements of Operations Year Ended December 31, 2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Tax Expense (Credit)TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDIT INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$136,962 73,353 240,425 450.740 100,466 80,391 37,582 104,960 42,898 22,295 43,620 22,471 (11.814)442.869 7,871 53,763 54,755 (289)20.845 (13,677)104 2001 (in thousands) | |||
$368,741 169,036 18.681 556.458 177,140 70,395 56,656 111,248 22,343 50,705 28,319 16.262 523.068 33,390 12,199 10,695 (691)23.275 12,310 104> t12 20l6$376,206 176,204 18,654 571,064 183,154 68,080 57,773 93,078 21,241 55,172 25,321 14,904 518.723 52,341 9,530 12,664 (1,459)23.216 27,450 104$ 27,3A6 2000 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
$(13,677) | |||
$12,310 $27,450 NET INCOME (LOSS)OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(15)-(30.74)i$12 1 3i The common stock of TNC is owned by a wholly owned subsidiary of AEP.see notes to Financial statements beginning on page L-1.D-4 AEP TEXAS NORTH COMPANY Statements of Retained Eaminqs Year Em 2002 (in BEGINNING OF PERIOD $105,970 i NET INCOME (LOSS) (13,677)DEDUCTIONS: | |||
cash Dividends Declared: Common Stock 20,247 Preferred stock 104 BALANCE AT END OF PERIOD 7192A2 The common stock of TNC is owned by a who77y owned subsidiary of AEP.see notes to Financial Statements beginning on page L-1.Jed December 31.2001 2000 thousands) | |||
;122,588 $113,242 12,310 27,450 28,824 104$1I0,7=0 18,000 104 D-5 AEP TEXAS NORTH COMPANY Balance Sheets December 31, 2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Allowance for Uncollectible Accounts Fuel Inventory Materials and Supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS See Notes to Financia7 Statements beginning on page L-1.$ 353,087 254,483 445,486 111,679 37.012 1,201,747 521.792 679 955 1,213 2.248 1,219 62,660 43,632 (5,041)12,677 9,574 6,829 4,130 1,070 136.750 45,097 11 912$877.175$ 443,508 250,023 431,969 112,797 22.575 1,260,872 546.162 714,710 24.933* 8.327 2,454 18,720 8,656 (196)8,307 11,190 10,240 966 60,337 54,122 2.446_$_8_64,875 D-6 AEP TEXAS NORTH COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock $25 Par value: Authorized 7,800,000 Shares outstanding 5,488,560 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred Stock Not subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
short-term Debt Affiliates Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES see Notes to Financia7 statements beginning on page L-1.$137,214 2,351 (30,763)71.942 180,744 2,367 132. 500 28, 861 125,000 80,407 32,714 76,217 117 3,697 2,776 3,801 17.414 342,143 117, 521 21.510 557 50,972$137, 214 2,351 105.970 245,535 2,367 220,967 468.869 6,296 35,000 50,448 33,782 11,388 4,191 17,358 4,762 12,402 9. 824 179 155 145.049 22,781 52 250 37.475$87,17 D-7 AEP TEXAS NORTH COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income (Loss)Adjustments to Reconcile Net Income to Net Cash Flows From operating Activities: | |||
Depreciation and Amortization writedown of Utility Assets writedown of wind Farm Assets Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: | |||
Construction Expenditures sales Proceeds and other Net Cash used For Investing Activities FINANCING ACTIVITIES: | |||
Retirement of Long-term Debt change in short-term Debt Affiliated (net)Change in Advances from Affiliates (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net Cash Flows From (used For) Financing Activities | |||
$(13,677) | |||
$ 12,310 $ 27,450 43,620 38,154 4,744 (12,275)(1,271)(1,127)(74,071)(2,754)(6,829)63,761 (13,661)14,169 (16,928)16, 514 38. 369 (43,563)150 (43,413)50,705 (11,891)(1,271)(3,506)24,844 3,187 (42,604)(1,543)32,505 (1,432)11,056 72. 360 (39,662)(127)(39.789)55,172 8,164 (1,271)2,590 (1,445)8,478 28,393 6,443 (53,841)15,465 2,549 (3.869)94,278 (64,477)(64,477)(130,799)125,000 29,959 (20,247)(104)3 809 (8,130)(28,824)(104)(37,058)(48,000)37,170 (18,000)(104)(28.934)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents at Beginning of Period Cash and cash Equivalents at End of Period (1,235)2,454$-1,2-19 (4,487)6.941 i__2,54 867 6.074 Supplemental Disclosure: | |||
Cash paid (received) for interest net of capitalized amounts was $19,934,000 | |||
$19,279,000 and$19,088,000 and for income taxes was $15,544,000, $21,997,000 and ($906,000) in 2002, 2001 and 2000 respectively. | |||
see Notes to Financia7 statements beginning on page L-1.D-8 AEP TEXAS NORTH COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) | |||
$180.744 S245.535 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 810,000 Call Price December 31, Number of Shares Redeemed Series 2002 Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption: | |||
4.40% $107 --1 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 Statements beginning on page L-1.shares outstanding December 31. 2002 23,672 2,367 2,367 88,190 44,310 132. 500 211,657 44,310 (35 000)220.967 D-9 AEP TEXAS NORTH COMPANY Schedule of LonQ-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousaniis-Y | |||
% Rate Due 6-7/8 2002 October 1 S -7 2004 October 1 18,469 6-1/8 2004 February 1 24,036 6-3/8 2005 October 1 37,609 7-3/4 2007 June 1 8,151 unamortized Discount (75)Q8 S 35,000 40,000 40,000 72,000 25,000 (343)i2IL-6S Under the terms of the installment purchase contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) 2003 $ -2004 42,505 2005 37,609 2006 -2007 8,151 Later Years 44 310 Principal Amount 132,575 Less: unamortized Discount C75)Total S First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due Red River Authority of Texas: 6.00 2020 June 1 December 31.2002 2001 (in thousands) 544310 S44,31 D-10 AEP TEXAS NORTH COMPANY Index to Combined Notes to Financial Statements The notes to TNC s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to TNC. The combined footnotes begin on page L-1.Combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued operations Note 12 Asset Imapairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of credit and Sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Jointly owned Electric utility Plant Note 28 Related Party Transactions Note 29 D-11 i INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas North Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 D-1 2 APPALACHIAN POWER COMPANY AND SUBSIDIARIES I APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data I .n" 11 IdnIA IJ .IIU 1* J.1 ... I -.----2002 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Gain Net Income Preferred stock Dividend Requirements Earnings Applicable to common Stock$1,814,470 1,512,407 302,063 20,106 116.677 205,492 205,492 2.897$ 202,195 2001$1,784,259 1.509.273 274,986 6,868 120,036 161,818 161,818 2.011$ 159&0QZ 2000 (in thousands) | |||
$1,759,253 1.558.099 201,154 11,752 148.000 64,906 8.938 73,844 2,504 1999$1,586,050 1,344,814 241,236 8,096 128.840 120,492 120,492 2.706 1998$1,672,244 1.443.701 228, 543 (8,301)126.912 93,330 93,330 2.497 December 31, 2002 2001 2000 (in thousands) | |||
BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant 1999$5,262,951 2.079.490$5,895,303 2.424.607$5,664,657 | |||
: 2. 296. 481$5,418,278 | |||
: 2. 188. 796 3229 ,482$6.522 l 9S 1998$5,087,359 1.,984. 856 SI-1MA61 14.35Z2 Total Assets Common Stock and Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Total Cumulative Preferred Stock_4 &62.7 847 V4,047,038 | |||
$ 977,700 (72,082)260,439 ,166 Q5Z$ 976,244 (340)150, 797 I 1,12-6 7 0-$ 975,676 120, 584$1.,096,260Q | |||
$ 974,717 175. 854$ 924,091 179.461$103A52$ 17,790 $ 17,790 10.860 10,860$ 17,790 10,860$ 28.650$1,605,818 | |||
$ 18,491 20,310$1__3 Oi t1<6 65,$ 19,359 22.310 Long-term Debt (a)obligations under Capital Leases (a)Total Capitalization And Liabilities IL,55-6-55-9 | |||
_$It55L455 Si__5d751z L-3i,5&89 t{A,621T4~ | |||
$ 46,281$ 64,645$4Z482,78$65 57255$4I,Q4ZQ38 (a) Including portion due within one year.E-1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operation APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 retail customers in southwestern Virginia and southern West Virginia. | |||
APCo, as a member of the AEP Power Pool, shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
APCo also sells wholesale power to municipalities. | |||
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs.The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs.Results of Operations Net Income increased | |||
$44 million or 27% in 2002 due to higher retail sales resulting from increased generation, weather related electricity demands and reductions in Maintenance expense. Most significantly, the Mountainer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased | |||
$10 million as a result of a reduction in trading incentive compensation recorded in Nonoperating Expenses offset in part by decreased power trading gains recorded in Nonoperating Income.Net Income increased | |||
$88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000.In February 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in net income was growth in and strong performance by the wholesale electricity business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales.Operating Revenues Operating Revenues increased | |||
$30 million or 2% in 2002 as a result of weather related demand and increased generation resulting from availablility of plants previously down for maintenance coming back online. An increase of $25 million, or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power Pool transactions. | |||
Changes in components of revenues were as follows: Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Amount % Amount %$16.0 2 S(11.7) (1)(1.0) -20.1 3 wholesale El ectri ci ty*Energy Delivery*Sales to AEP Affiliates Total Revenues 15.2 5302 9 2 16.6 L25 0 11 1*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Operating Revenues for 2002 increased as a result of an increase in generation and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in residential and commercial sales due to warmer weather during July and September. | |||
Sales to AEP affiliates increased for the year due to an E-2 increase in generation capacity and power available to be delivered to AEP Power Pool.These increases were partially offset by flat industrial sales as recessionary conditions continued into 2002.The year 2001 saw a decrease in kilowatt hour sales to industrial customers. | |||
This decrease was due to the economic recession. | |||
In the fourth quarter, sales to residential and commercial customers declined, reflecting recession-related reductions in demand.The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP Power Pool transactions. | |||
As the quantity of energy sold by the AEP Power Pool rose, APCo s contribution of energy to the Pool rose, accounting for the increase in APCo s revenues from Sales to AEP Affiliates. | |||
Operating Expenses Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Power expenses were offset by decreases in power purchases from AEP Affiliates due to increases in APCo generation and availability as plants previously down for maintenance resumed operations. | |||
The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity purchased power expense and depreciation and amortization expenses.Changes in the components of Operating Expenses are as follows: Increase (Decrease) | |||
From Previous Year (dolTlars in millions)2002 2001 Amount % Amount %Fuel S 79.4 23 S (17.6) (5)of an increase in APCo generation. | |||
Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability in 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. | |||
Wholesale Electricity Purchases increased for 2002 as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. Electricity purchased power expense increased in 2001 due to increases in wholesale electricity prices and as a result of the previously mentioned plant outages.The decrease for 2002 in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability. | |||
Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo s MLR.Other Operation expense increased in 2002 mainly due to severance expenses related to the sustained earnings initiative plan, a reduction in the gains recorded on the dispositions of S02 emission allowances, and increased insurance premiums and other employee benefit costs. These increases were offset by reduced trading overhead expenses as a result of reduced staffing and weaker market conditions; a decrease in transmission equalization charges caused by a reduction in APCo s MLR ratio; and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. | |||
Additionally, the decrease was the result of a gain recorded on the disposition of S02 emission allowances offset in part by increased wholesale power trading incentive compensation expense.The decrease in Maintenance expense in 2002 is primarily due to previously discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in the year 2001.wholesale Electricity Purchases 15.0 36 AEP Affiliate Purchases (112.3) (32)other operation 8.9 3 Maintenance (10.2) (8)Depreciation and Amortization 8.9 5 Taxes other Than Income Taxes (4.6) (5)Income Taxes 18.0 19 Total __3.1 -17.4 70 (8.9) (3)(18.6) (7)7.9 -6 17.3 11 (11.8)(34. 5)(11)(27)(3)Fuel expense increased for 2002 as a result E-3 Depreciation and Amortization expense increased during 2002 due to increased amortization for the net generation-related regulatory assets related to the Companys West Virginia jurisdiction which were assigned to the distribution portion of the Companys business and are being recovered through regulated rates. Investment in production plant in service, primarily equipment related to emission control, contributed to the increase in depreciation and amortization expense.Depreciation and Amortization expense increased in 2001 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets in the Virginia and West Virginia jurisdictions. | |||
Additional investments in distribution and transmission plant also contributed to the increases in depreciation and amortization expense in 2001. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. | |||
Consequently net generation-related regulatory assets were assigned to the energy delivery businesss regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates.trading gains driven by a decline in market prices. Nonoperating Expenses decreased as a result of decreased trading incentives. | |||
The increase in Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable increases in the level of activity in the wholesale business s trading transactions outside of the AEP System s traditional marketing area.Interest Charges Interest Charges for 2002 decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. | |||
Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000.The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily to a decrease in municipal license tax. The municipal license tax was replaced by the Virginia consumption tax. The municipal license tax was imposed on APCo and the Virginia consumption tax is imposed on the customer with APCo acting as collector agent.The decrease in Taxes Other Than Income Taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state.The increase in Income Taxes for 2002 was due to an increase in pre-tax income. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income.Nonoperating Income and Nonoperating Expenses The Nonoperating Income decrease for 2002 was due primarily to a decrease in net power E-4 | |||
'!APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates Total Operating Revenues OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total operating Expenses OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (BENEFIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY GAIN DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) | |||
NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS | |||
$1,'1.Year Ended December 3 2002 2001 (in thousands) | |||
)33,904 $1,017,938 594,089 595,036 186.477 171,285 314.470 1.784.259 430,963 57,091 234,597 269,426 122,209 189,335 95,249 113.537 1,512.407 302,063 29,278 11,783 (2,611)116.677 205,492 205,492 2.897 L.351,557 42,092 346,878 260,518 132,373 180,393 99,878 95. 584 1,509.273 274,986 49,507 41,500 1,139 120.036 161,818 161,818 2.011 2000$1,029,657 574,918 154.678 1.759.253 369,161 24,720 355,774 279,114 124,493 163,089 111,692 130.056 1.558.099 201,154 31,204 16,329 3,123 148.000 64,906 8.938 73,844 2.504 EARNINGS APPLICABLE TO COMMON STOCK-$ZLn-A0 Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
NET INCOME $205,492 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge (1,580)Minimum Pension Liability (70,162)COMPREHENSIVE INCOME $13,50 see Notes to Financia7 Statements beginning on page L-1.$161,818 $73,844 (340)S161,AI A E-5 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31.2002 2001 2000 (in thousands) | |||
$150,797 $120,584 $175,854 205.492 161,818 73,844 356.289 282.402 249,698 Retained Earnings January 1 Net Income Deductions: | |||
cash Dividends Declared: Common stock Cumulative Preferred Stock: 4-1/2% series 5.90% Series 5.92% Series 6.85% series Total cash Dividends Declared capital Stock Expense Total Deductions Retained Earnings December 31 See Notes to Financia7 Statements beginning on page L-1.92,952 801 278 364 94,395 1.455 95.850$260,4139-129, 594 801 278 364 131,037 568 131.605$150, 797 126,612 811 307 364 289 128,383 731 129.114 E-6 | |||
--APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmi ssion Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Mi scellaneous Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial Statements beginning on page L-1.$2,245,945 1,218,108 1,951,804 272,901 206.54 5 5 ,895,303 2,424.607 3,470.696 54.653 115,748 4,285 132,266 122,665 28, 629 (13,439)53,646 59,886 30,948 94,238 13.396 526.,520 395.,553 64. 677$2,093,532 1,222,226 1,887,020 257,957 203,922 5, 664 ,657 2. 296. 48.3. 368. 176 53. 736 119,638 13,663 113,371 63,368 11,847 (1,877)56,699 59,849 30,907 137,742 16.018 501.587 397. 383 42, 265 E-7 APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock No Par value: Authorized 30,000,000 shares outstanding 13,499,500 Shares Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareowner s Equity Cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Taxes Accrued Customer Deposits Interest Accrued Energy Trading and Derivative Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.$ 260,458 717,242 (72,082)260.439 1,166,057 17,790 10,860 1,738,854 2,933,561 173.438 155,007 39,205 141,546 98,374 29,181 26,186 22,437 69,001 79. 832 660.769 701.801 33.691 44.517 80,070$4,62L,847 | |||
$ 260,458 715,786 (340)150.797 1,126,701 17,790 10,860 1.476. 552 2.631.903 84,104 80,007 291,817 127,597 84,518 55,583 13,177 21,770 121,161 79.089 874.719 703. 575 38,328 60. 518 89, 638 A4-82, 25 E-8 APPALACHIAN POWER COMPANY AND SUBSIDIARIES consolidated Statements of Cash Flows Year Ended December 2002 2001 (in thousands) 31.2000 OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Power Supply Costs (net)Mark-to-Market of Energy Trading Contracts Provision for Rate Refunds Extraordinary Gain Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Revenue Refunds Accrued Incentive Plan Accrued Disputed Tax and Interest Related to COLI change in operating Reserves Rate Stabilization Deferral change in other Assets change in other Liabilities Net Cash Flows From Operating Activities INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From sales of Property and other Net Cost of Removal and Other Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Change in Advances From Affiliates Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net cash Flows used For Financing Activities | |||
$ 205,492 189,335 16,777 (4,637)6,365 (21, 151)(83,412)3,016 (41)27,805 (26,402)(858)(3,190)(43,337)14,948 280,710$ 161,818 180, 505 42,498 (4,765)1,411 (68,254)134,099 (19,957)35,592 (45,073)(7,675)(2,451)(5,358)19,418 (27.954)393. 854$ 73,844 163,202 8,602 (4,915)(84,408)(1,843)(4,818)(8,938)(166,911)18,487 (13,081)159,369 14,220 181 10,662 72,440 (19,770)75,601 (13,021)9.817 288. 720 (276, 549)1,074 (275.475)647,401 (315,007)(252,612)(92,952)(1.443)(14,613)(306,046)1,182 (8.434)(313.298)124,588 (175,000)(191,495)300,204 (129,594)(1.443)(72.740)(199,285)159 (7.500)(206. 626)74,788 (9,924)(136,166)68,015 (8,387)(126,612)(1.938)(140,224)Net Increase (Decrease) in cash and Cash cash and cash Equivalents January 1 cash and cash Equivalents December 31 Equivalents (9,378)13.663$ 4,285 7,816 5 $ 847 (58,130)63.977$ A Z supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000 and$124,579,000 and for income taxes was $125,120,000, $56,981,000 and $63,682,000 in 2002, 2001 and 2000, respectively. | |||
There were no noncash acquisitions under capital leases in 2002. In 2001 and 2000, non cash acquisitions under capital leases were $2,510,000 and $14,116,000, respectively. | |||
see Notes to Financia7 Statements beginning on page L-1.E-9 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
S1.166.057 | |||
$1.126.701 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: No par value -authorized shares 8,000,000 call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption (b): 4-1/2% $110 6 -7,011 subject to Mandatory Redemption (b): 5.90% cc) --10,000 5.92% Cc) _ _ -shares Outstanding December 31. 2002 177,899 47,100 61, 500 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Junior Debentures other Long-term Debt Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 17.790 4,710 6.150 10.860 489,697 235,027 1,166,609 2,528 (155.007)1.738.854 17.790 4,710 6.150 10.860 639,365 234,904 518,247 161, 507 2,536 (80.007)1.476.552 52,631,903 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends. | |||
The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.(b) The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date.(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90%series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirement. | |||
see Notes to Financial statements beginning on page L-1.E-1 0 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 7.38 2002 7.40 2002 6.65 2003 6.85 2003 6.00 2003 7.70 2004 7.85 2004 8.00 2005 6.89 2005 6.80 2006 8.50 2022 7.80 2023 7.15 2023 7.125 2024 8.00 2025 unamortized Total August 15 '-December 1-May 1-June 1-November 1-September 1-November 1-May 1-June 22-March 1-December 1-May 1-November 1-May 1-June 1 Discount S -30,000 21,000 50,000 50,000 30,000 100,000 70,000 30,237 20,000 45,000 45,000-1C 540)$ 50,000 30,000 40,000 30,000 30,000 21,000 50,000 50,000 30,000 100,000 70,000 30, 237 20,000 45,000 45,000 (1.872)M69,36 Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands) | |||
First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
X Rate Due (a) 2003 August 20 S 125,000 5125,00 7.45 2004 -November 1 50,000 50,00 4.80 2005 June 15 450,000 -4.32 2007 November 12 200,000 -6.60 2009 -May 1 150,000 150,00 7.20 2038 -March 31 100,000 100,00 7.30 2038 -June 30 100,000 100,00 unamortized Discount 8 391 6.75 Total VIA609 S51,2 (a) A floating interest rate is determined monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, respectively. | |||
0 0 0 0 0 z Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds, by governmental authorities as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due Industrial Development Authority of Russell county, Virginia: Junior debentures outstanding were as follows: December 31.2002 2001 (in thousands) 8-1/4% Series A due 2026 September 30 8% Series B due 2027-March 31 unamortized Discount Total S -S 75,000 90,000 (3 .493)U161, 50 7.70 2007 -November 1 S 17, 500 5.00 2021 -November 1 19,500 Putnam County, West Virginia: S 17, 500 19, 500 At December 31, 2002, future annual long-term debt payments are as follows: 5.45 2019 -June 1 41 6.60 2019 -July 1 3 Mason County, West Virginia: 7-7/8 2013 -November 1 1 6.85 2022 -June 1 4 6.60 2022 -October 1 5 6.05 2024 -December 1 3 unamortized Discount Total 0,000 40,000 0,000 30,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 155,007 121,008 530,010 100,011 217,513 782. 216 1,905,765 (11,904)0,000 0,000 0,000 0,000 1. 973)10,000 40,000 50,000 30,000 (2 096)1234.90A E-1 1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to APCO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to APCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investments Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note Note Note Note Note Note Note 17 18 20 22 23 24 29 E-1 2 INDEPENDENTAAUDITORS REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian PowerCompanyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance aboutwhetherthe financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 E-1 3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable to common Stock$1,400,160 1180T3 81 219,779 15,263 53. 869 181,173 181,173$1,350,319 1.098.142 252,177 7,738 68.015 191,900 (30.024)161,876$1,304,409 1.108.532 195,877 5,153 80,828 120,202 (25. 236)94,966$1,190,997 968.207 222,790 2,709 75. 229 150,270 150,270 2.131$18 139$1,187,745 975, 534 212,211 (1,343)77.824 133,044 133,044 2.131£ 410Q9f 1.095$ 160.781£__1798JA1 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$3,467,626 1.465.174£2_Q02 ,452$Z,153,240 | |||
$3,354,320 1.377.032$1,977,288 3$Z.2 "388$3,266,794 1.299.697$3,151,619 1.210.994£1,40,625$ &08Q8123$3,053,565 1.134. 348$1,912,=21 | |||
_$13 X&ZL42i Common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$ 616,410 (59,357)290.611$_847 7 604$ 615,395 176.103=$ 191 9,AH$ 614,380 99.069$ 713,449$ 613,899 246, 584$860.,483$ 613,518 186.441$Z 79R9,9 cumulative Preferred stock -subject to Mandatory Redemption (a)Long-term Debt (a)Obligations under Capital Leases (a)Total Capitalization and Liabilities L$ L6 1 Q6Z R 2$ i_ 4 Q$L 72293&$ 252i0f$L 25,000$ _ 9 2 4 .5 4 5 L Z &S 4_0ZZ0 L A42L3Z$3,87,491 (a) Including portion due within one year.F-1 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Manaaement s Narrative Analysis of Results of ODerations Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 689,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
CSPCo also sells wholesale power to municipalities. | |||
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each companies percentage share of AEP Power Pool revenues and costs.Results of Operations Net Income increased | |||
$19 million or 12% in 2002 due to reduced interest charges and a$30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio excise taxes stranded by Ohio deregulation offset by higher operating expenses.Operating Revenues Operating Revenues increased in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. | |||
Changes in the components of Operating Revenues were: Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount %Retail* S51 8 wholesale Marketing 3 2 unrealized MTM (4) (22)Other 1 3 wholesale Electricity* | |||
51 6 Energy Delivery* | |||
9 2 Sales to AEP Affiliates (10) (15)Total Revenues $5Q 4* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 35%. For the fall season, heating degree days increased 34%. This reflects a return to more normal weather conditions since the weather experienced in 2001 was abnormally mild.Operating Expenses Operating Expenses increased in 2002 mainly as a result of purchased power, operating expenses and state taxes.Changes in the components of Operating Expenses were: Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount X Fuel wholesale Purchased Power AEP Affiliates Purchased Power other operation Expenses Maintenance Expense Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total$10 4 18 18 (2)4 25 5 6 37 6 8 (4)3 22 5 7 10%by a coal Fuel cost increased as a result of a increase in generation partially offset slight cost decrease per ton of consumed.Wholesale Purchased Power increased in 2002 due to increased purchases from third F-2 parties for resale to wholesale customers and to meet internal demand.Expenses related to AEP Affiliates Purchased Power increased due to greater system pool capacity charges.The increase in Other Operation expenses was attributable to a number of factors: higher OPEB post retirement costs as a result of higher medical cost and lower investment performance, 2002 Sustained Earnings Initiative Expenses, and the 2001 reversal of a quality of service liability accrual. The increase was partially offset by a reduction in energy trading overheads reflecting reduced marketing activity.The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in property taxes and a full year of the state excise tax which replaced the state gross receipts tax during 2001.The increase in Income Taxes is predominately due to an increase in state taxes as a result of the State of Ohio s tax legislation resulting from utility deregulation. | |||
This increase was offset in part by a decrease in federal taxes due to a decrease in pre-tax operating income.Nonoperating Income and Nonoperating Expense The decrease in Nonoperating Income in 2002 is due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System s traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. CSPCo s share of the AEP Power Pool s gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in Nonoperating Income. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand.The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy trading incentive compensation. | |||
Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax nonoperating income.Interest Charges Interest Charges decreased in 2002 primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.F-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income 2002 Year Ended December 31.2001 (in thousands) 2000 OPERATING REVENUES: wholesale Electricity Energy Delivery sales to AEP Affiliates Total operating Revenues OPERATING EXPENSES: Fuel Purchased Power: Wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME S 850,680 492,278 57,202 1.400.160 185,086 15,023 310,605 237,802 60,003 131,624 136,024 104.214 1,180.381 219,779 26,360 S 799,589 483,219 67,511 1,350.319 175,153 10,957 292,199 219,497 62,454 127,364 111,481 99.037 1 098.142 252,177 32,756 21,095 3,923 68,015 191,900 (30.024)161,876 1.095$ 856,998 398,046 49. 365 1,304.409 189,155 9,879 287,750 219,840 69,676 99,640 123,223 109, 369 1.108, 532 195,877 20,580 8,070 7,357 80.828 120,202 (25, 236)94,966 1.783$ ~93,13 NONOPERATING EXPENSES 4,308 NONOPERATING INCOME TAX EXPENSE INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 6,789 53 869 181,173 181,173 1.332$ 179, 841 Consolidated Statements of Comprehensive Income 21 Year Ended December 31.'02 2001 2000 (in thousands) 1,173 $161,876 $94,966 NET INCOME 18: OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability (M COMPREHENSIVE INCOME $12 The common stock of the CSPCo is who7ly owned by AEP.See Notes to Financial Statements beginning on page L-1.(267)9. 090)3261,B 6 594--9-U F-4 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eaminqs Year Ended December 31.2002 2001 2000 (in thousands) | |||
Retained Earnings January 1 Net Income Deductions: | |||
cash Dividends Declared: Common Stock Cumulative Preferred Stock Total cash Dividends capital stock Expense Total Deductions Retained Earnings December 31$176,103 181,173 357,276 7% series Declared 65,300 350 65,650 1.015 66.665$290,611.$ 99,069 161.876 260.945 82,952 875 83,827 1.015 84.842$i176,13$246,584 94.966 341.550 240,600 1.400 242,000 481 242.481 SL32Pa9 see Notes to Financial Statements beginning on page L-1.F-5 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation | |||
$1,582,627 413,286 1,208,255 165,025 98.433 3,467,626 1.465,174 NET ELECTRIC UTILITY PLANT 2,002X452 OTHER PROPERTY AND INVESTMENTS 35.759 LONG-TERM ENERGY TRADING CONTRACTS 77.810$1,574,506 401,405 1,159,105 146,732 72.572 3,354,320 1,377.032 1,977.288 40.369 73. 310 12,358 41,770 63,470 16,968 (745)20,019 38,984 7,087 84,323 28.733 312.967 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Energy Trading Contracts Prepayments and other Current Assets TOTAL CURRENT ASSETS 1,479 31,257 49,566 54,518 22,005 (634)24,844 40,339 12,671 63,348 7.308 306.701 REGULATORY ASSETS 257.682 DEFERRED CHARGES 72,836$2,753,240 262.267 56,187$2,722,388 TOTAL ASSETS see Notes to Financia7 Statements beginning on page L-1.F-6 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock No Par value: Authorized 24,000,000 shares outstanding 16,410,426 shares Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity cumulative Preferred stock subject to Mandatory Redemption Long-term Debt -General Long term Debt Affiliated companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year General Long-term Debt Due within One Year Affiliated Companies short-term Debt Affiliated Companies Advances from Affiliates Accounts Payable General Accounts Payable Affiliated companies Taxes Accrued Interest Accrued Energy Trading Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 41,026 575,384 (59,357)290.611 847,664 418,626 160,000 1,426.290 95,460 43,000 290,000 89,736 81,599 112,172 9,798 46,375 36,790 709.470 437.771 33.907 29.926 20.416$Za53 24Q$ 41,026 574,369 176,103 791,498 10,000 571,348 1.372.846 36,715S 20,500 200,000 181, 384 60,689 83,697 116,364 10,907 72,082 36, 305 781,928 443, 722 37.176 37.101 12.900£tZ722 za83 F-7 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark to Market of Energy Trading Contracts Extraordinary Loss Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities S 181,173 131,753 23,292 (3,269)(16,667)(3,992)(6,180)(5,584)26,949 (8,027)(22,448)297,000$ 161,876 128,500 24,108 (4,058)(44,680)30,024 19,987 (7,780)2,551 (16,249)(42,066)(18,769)233,444 S 94,966 100,182 (4,063)(3,482)5,352 (3,393)25,236 (29,737)11,957 38,479 81,284 39,483 (121,115)132.44 367,590 INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From Sales and Leaseback Transactions and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
change in Advances from Affiliates (net)Issuance of Affiliated Long-term Debt Retirement of Preferred Stock Retirement of General Long-term Debt Retirement of Affiliated Long-term Debt Change in short-term Debt (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows used For Financing Activities (136,800) | |||
(132,532)730 (136,070)(212,641)160,000 (10,000)(133,343)(200,000)290,000 (65,300)(525)(171 809)10.84 (121.691)92,652 200,000 (5,000)(314,733)(82,952)(962)(110.995)(127,987)1. 560 (126.427)88,732 (10,000)(25,274)(45,500)(240,600)(1.575)(234,217)Net Increase (Decrease) in cash and cash Cash and cash Equivalents January 1 cash and Cash Equivalents December 31 Equivalents (10,879)12.358 3-1"79 758 11,600 S-1 3-5-8 6,946 4.654 S-II&M0 supplemental Disclosure: | |||
cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000 and$68,506,000 and for income taxes was $117,591,000, 80,485,000 and $81,109,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were S1,o09,000 and $10,777,000 in 2001 and 2000, respectively. | |||
See Notes to Financial Statements beginning on page L-1.F-8 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of CaDitalization December 31.2002 2001 (in thousands) | |||
COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:. S100 par value authorized shares 2,500,000 525 par value -authorized shares 7,000,000$ 847.664 S 791.493 series Number of shares Redeemed Year Ended December 31, 2002 2001 2000 shares outstanding December 31, 2002 Subject to Mandatory Redemption: | |||
7.00% 100,000 50,000 100,000 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior unsecured Notes Notes Affiliated Junior Debentures Less Portion Due within one Year Total Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 222,797 91,275 147,554 160,000 ( 43.000)578.626 S1L 42,9 243,197 91,220 147,458 200,000 109,973 (220. 500)571. 348 1S1,7-21, A-C see Notes to Financial statements beginning on page L-1.F-9 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
December 31.2002 2001 (in thousands) | |||
% Rate Due 7.25 2002 7.15 2002 6.80 2003 6.60 2003 6.10 2003 6.55 2004 6.75 2004 8.70 2022 8.55 2022 8.40 2022 8.40 2022 7.90 2023 7.75 2023 7.60 2024 unamortized Total October 1 S -November 1 May 1 13,000-August 1 25,000 November 1 5,000 March 1 26,500 May 1 26,000 July 1 2,000 August 1 15,000 August 15 14,000 October 15 13,000 May 1 40,000 August 1 33,000 May 1 11,000 Discount (703)$ 14,000 6,500 13,000 25,000 5,000 26, 500 26,000 2,000 15,000 14,000 13,000 40,000 33,000 11,000 (803)% Rate Due 6.85 2005 6.51 2008 6.55 2008 unamortized Total October 3 $ 36,000 February 1 52,000 June 26 60,000 Discount (446)S 36,000 52,000 60,000 (542)Notes payable to parent company were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate (a)6.501%Total Due 2002 -Sept 25 S -2006 May 15 160.000 S 160,00$200,000 First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: | |||
December 31, 2002 2001 (in thousands)(a) Redemed 9/25/02 Junior debentures outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due 8-3/8 2025 7.92 2027 unamortized Total Sept 30 S -March 31 -Discount -5~S 72,843 40,000 (2.870)At December 31, 2002, future annual long-term debt payments are as follows:% Rate Due 6-3/8 2020 -December 1 $48,550 6-1/4 2020 -December 1 43,695 unamortized Discount (970)Total 191,m$48,550 43,695 (1.02 5)2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 43,000 52,500 36,000 160,000 332.245 623,745 (2.119)5621 Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant.F-1 0 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to CSPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to CSPCo.The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer Choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Jointly owned Electric Utility Plant -Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 28 Note 29 F-1 I INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company s management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 F-1 2 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY Selected Consolidated Financial Data AND SUBSIDIARIES Yea 2002 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income (Loss)Nonoperating Items, Net Interest charges Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$1,526,764 1.375,575 151, 189 16,726 93.923 73,992 4.601 2001$1, 526,997 1.367,292 159,705 9,730 93. 647 75,788 ir Ended December 31.2000 1999 (in thousands) | |||
$1,488,209 1.522.911$1,351,666 1.243,014 (34,702) 108,652 1998$1,405,794 1,239,787 166,007 (839)68.540 96,628 4.824 9,933 107. 263 (132,032)4,530 80.406 32,776 4.621 4,885$ 71,167$ 27,891 2002 2001 December 31, 2000 (in thousands) | |||
_ _ _ _1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$5,029,958 2,568.604$2,.461,3~54 i48L28719$4,923,721 2.436.972$2,486, 749$4,871,473 | |||
: 2. 280.521$2.,590.,952 | |||
$4,770,027 2.194.397$2,5575,30 | |||
$4,631,848 2.081, 355$2.,550.,493 Total Assets common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption (a)Total Cumulative Preferred stock$ 915,144 (40,487)143.996$ 789,800 (3,835)74,605$ 789,656 3,443$ 789,323 166.389$ 789,189 2 53.154$108,11 $ 8,36 S 793,099 6 $ 9,552, $1 273 S 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 64.945$163,046$1, 617,062 64, 945 11,652-Q&Z 64,945$1,388,939 64.945$£ 74.193$1,324, 3-26 68.445$ 7-7.718 Long-term Debt (a)obligations under capital Leases (a)$ 50,848$ 61L933$-163,173$ 187,965$ 186,427 Total capitalization And Liabilities A 58L7191 4. 394 062$5,774 108$4,575,210 (a) Including portion due within one year.G-1 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 571,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. | |||
As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers. | |||
I&M also sells wholesale power to municipalities and electric cooperatives. | |||
The cost of the AEP Power Pool s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs.maintenance costs incurred as part of planned and unplanned outages at Cook Plant and Rockport Plant.During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection (see Note 5).As a result of costs incurred in 2000 to restart the Cook Plant and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, Net Income increased in 2001 by $208 million. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including l&M, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. The deferrals were expensed and impacted Net Income in 2000.Operatina Revenues Increase Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. | |||
AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo s Rockport Plant capacity to KPCo through 2004. The KPCo agreement extends until December 31, 2009 for Rockport Unit I and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. | |||
Therefore, l&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.Results of Operations During 2002 Net Income decreased by $2 million due to increased operations and Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase reflects increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in Operating Revenues: Increase (Decrease) | |||
From Previous Year (dollars in milions)2002 2001 Amount % Amount %Retail* $ 28.2 Marketing | |||
===2.6 other=== | |||
2.6 Total wholesale Electricity 33.4 Energy Dellvery* | |||
===7.3 sales=== | |||
to AEP Affiliates (40 Total 4 1 6 S (2.3)(12.0)5 .0 N.M (4)13 3 (9.3) (1)2 3.4 1) (16) 44.7) N.M. 3.3 21 3 N.M. = Not Meaningful | |||
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.G-2 The increase in Operating Revenues in 2001 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power l&M could sell to its affiliates in the AEP Power Pool.Operating Expenses Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000. The changes in the components of Operating Expenses were: Plant nuclear units for restart with their return to service in 2000. Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002.The increase in Depreciation and Amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of l&M s share of deferred merger costs.Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment of amounts recorded in December 2000 to actual expenses.Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income. The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income.Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Fuel I wholesale Electricity Purchases AEP Affiliate Purchases Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total I Amount % Amount %'0(10.6) (4) $ 39.2 19 4.7 25 4.9 36 (4.5)13.6 24.3 3.8 (7.8)(15.2)w--(2)3 19 (27.2) (10)(147.7) (25)(92.6) (42)2 9.3 6 (12) 4.9 8 (28) 53.6 N.M.1 ) (10)Nonoperating Income.Expenses and Income Taxes Nonoperating N.M. = Not Meaningful Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. | |||
The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs.The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21 %.Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. | |||
The decrease in Other Operation and Maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP s traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP s traditional marketing area.Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders incentive compensation. | |||
Nonoperating Expenses increased in 2001 due to increased trading overheads and traders incentive compensation. | |||
The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income.Interest Charges The decrease in 2001 Interest Charges reflects the recognition in 2000 of deferred G-3 interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998. | |||
G-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME (LOSS)NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$ 990,905 321,721 214,138 1. 526. 764 239,455 23,443 233,724 462,707 151,602 168,070 57,721 38. 853 1. 375. 575 151,189 93,739 71,029 5,984 93. 923 73,992 4.601$ 957,548 314,410 255.039 1,526.997 250,098 18,707 238,237 449,115 127,263 164,230 65,518 54.124 1. 367,292 159,705 97,810 83,037 5,043 93 647 75,788 4.621 S 71,167$ 966,882 311,019 210.308 1.488.209 210,870 13,785 265,475 596,861 219,854 154,920 60,622 524 1.522.911 (34,702)76,499 62,377 4,189 107.263 (132,032)4,624$ 315,2656)Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
NET INCOME (LOSS) $ 73,992 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 3,835 Cash Flow Power Hedge (286)Minimum Pension Liability (40,201)COMPREHENSIVE INCOME (LOSS) $ 37, see Notes to Financia7 statements beginning on page L-1.$75,788 $(132,032) | |||
(3,835)-Z2 5113Z-02)G-5 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings 2002 Year Ended December 31.2001 (in thousands) 2000 Retained Earnings January 1 Net Income (Loss)Deductions: | |||
cash Dividends Declared: Common stock cumulative Preferred stock: 4-1/8% series 4.56% Series 4.12% series 5.90% series 6-1/4% series 6.30% series 6-7/8% series Total Cash Dividends Declared capital stock Expense Total Deductions | |||
$ 74,605 73, 992 148, 597 S 3,443 75.788-79.231$ 166,389 (132.032)34. 357 229 66 52 897 1,203 834 1.186 4,467 134 4.601 229 66 72 897 1,203 834 1.186 4,487 139 4.626 26,290 230 66 74 897 1,203 834 1,186 30,780 134 30.914 Retained Earnings December 31 $143 See Notes to Financia7 statements beginning on page L-1.S 74,6L05$3 1 A443 G-6 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 (in thousand 2001 S)ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General (including nuclear fuel)Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$2,768,463 971,599 921,835 220,137 147.924 5,029,958 2.568,604 2.461. 354$2,758,160 957,336 900,921 233,005 74.299 4,923,721 2,436.972 2.486.749 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870.754 834,109 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83, 265 OTHER PROPERTY AND INVESTMENTS 120,941 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading and Derivative Contracts Accrued Utility Revenues Prepayments and other TOTAL CURRENT ASSETS 3,237 191,226 67,333 122,489 30,468 (578)32,731 95,552 68,148 6,511 11,899 629.016 127.977 16,804 46,309 60,864 31,908 25,398 (741)28,989 91,440 108,895 2,072 6.497 418.435 REGULATORY ASSETS 348.212 408,927 DEFERRED CHARGES 73.649 34,967 TOTAL ASSETS$4,58,191 see Notes to Financia7 Statements beginning on page L-1.G-7 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
common Stock -No Par value: Authorized | |||
-2,500,000 shares outstanding | |||
-1,400,000 Shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION | |||
$ 56,584 858,560 (40,487)143 996 1,018,653 8,101 64,945 1.587,062 2,678, 761 620,672 138.965 759.637$ 56,584 733,216 (3,835)74.605 860,570 8,736 64,945 1. 3123082 2.246. 333 600,244 87,025 687,269 OTHER NONCURRENT LIABILITIES: | |||
Nuclear Decommissioning other TOTAL OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within one Year Accounts Payable General Accounts Payable -Affiliated Companies Taxes Accrued Interest Accrued obligations under capital Leases Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES 30,000 125,048 93,608 71,559 21,481 8,229 48,568 92. 822 491,315 340,000 86,766 43,956 69,761 20,691 10,840 93,413 76 486 741.913 DEFERRED INCOME TAXES 356,197 400,531 DEFERRED INVESTMENT TAX CREDITS 97,709 105,449 DEFERRED GAIN ON SALE AND LEASEBACK | |||
-ROCKPORT PLANT UNIT 2 73,885 77, 592 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32, 261 42,936 92,039 REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES | |||
$4 58iLL191.$4,3940Q6Z See Notes to Financia7 Statements beginning on page L-1.G-8 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income (Loss)Adjustments for Noncash Items: Depreciation and Amortization Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net)Amortization of Nuclear Outage Costs Deferred Income Taxes Deferred Investment Tax credits Unrecovered Fuel and Purchased Power Costs Changes in Certain Current Assets And Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and Supplies Accrued utility Revenues Accounts Payable Taxes Accrued Mark-to-Market of Energy Trading and Derivatives Contracts Disputed Tax and Interest Related to COLI Regulatory Asset Trading Losses Regulatory Liability Trading Gains change in other Assets Change in other Liabilities Net cash Flows From Operating Activities | |||
$ 73,992 168,070 (26,577)40,000 (16,921)(7,740)37,501 (102,283)(7,854)(4,439)87,934 1,798 (9,517)(992)2,494 (28,233)21.001 228.234$ 75,788 166,360 418 40,000 (29,205)(8,324)37,501 64,841 (19,426)(2,072)(60,185)1,345 (62,647)8,493 34,293 (5,871)(5,102)236,207$ (132,032)163,391 5,737 40,000 (125,179)(7,854)37,501 (25,305)10,743 44,428 85,056 19,446 14,830 56,856 (17,914)(7,416)(68,160)37.309 131.437 INVESTING ACTIVITIES: | |||
Construction Expenditures Bu yout of Nuclear Fuel Leases Other Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES: | |||
capital Contributions from Parent Company Issuance of Long-term Debt Retirement of cumulative Preferred Stock Retirement of Long-term Debt change in Advances from Affiliates (net)change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and Cash Equivalents January 1 cash and cash Equivalents December 31 (167,484)1. 759 (165 .72 5)125,000 288,732 (424)(340,000)(144,917)(4.467)(76.076)(91,052)(92,616)1,074 (182.594)297,656 (44,922)(299,891)(4.487)(51.644)(171,071)587 (170.484)199,220 (314)(148,000)253, 582 (224,262)(26,290)(3. 368).50. 568 (13,567)16.804 1,969 11,521 14.835 3,314 l_6104 S 14, 835 Supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000 and$82,511,000 and for income taxes was $60,523,000, $100,470,000 and $73,254,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were $1,023,000 and$22,218,000 in 2001 and 2000, respectively. | |||
see Notes to Financial Statements beginning on page L-1.G-9 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
$1.018.653 S 860.570 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:$100 Par value -Authorized 2,250,000 shares$25 Par value -Authorized 11,200,000 shares call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not Subject to Mandatory Redemption-$100 Par: 4-1/8% 106.125 20 -3,750 4.56% 102 ---4.12% 102.728 6,326 -1,375 Subject to Mandatory Redemption-S100 Par(b): 5.90% (c) ---6-1/4% (c) ---6.30% (c) ---6-7/8% (d) ---shares outstanding December 31. 2002 55,369 14,412 11,230 152,000 192,500 132,450 172,500 5,537 1,441 1. 123 8.101 15,200 19,250 13,245 17.250 64.945 5,539 1,441 i1. 756 8.736 15,200 19, 250 13,245 174 950 64.945 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 174,245 264,141 Installment Purchase Contracts 310,336 310,239 senior unsecured Notes 747,027 696,144 other Lon -term Debt (e) 223,736 219,947 Junior Debentures 161,718 161,611 Less Portion Due within one Year (30.000) (340.000)Long-term Debt Excluding Portion Due within one Year 1.587,062 1.312,082 TOTAL CAPITALIZATION 4S2j1 SZ,2A33 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends (b) sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of these due dates. Shares previously purchased may be applied to meet the sinking fund requirement. | |||
cc) commencing in 2004 and continuing through 2008 I&M may redeem at $100 per share, 20,000 shares of the 5.90%series, 15,000 shares of the 6-1/4% series and 17,500 shares of? the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. The series are callable beginning November 1, 2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March 1, 2004 for the 6.30% series at $100 plus accrued dividends.(d) commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. callable at $100 per share plus accrued dividends beginning February 1, 2003.(e) Represents a liability for SNF disposal including interest payable to the DOE. See Note 9.See Notes to Financial Statements beginning on page L-1.G-10 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 7.60 2002 7.70 2002 6.10 2003 8.50 2022 7.35 2023 7.20 2024 7.50 2024 unamortized November 1 December 1-November 1-December 1 October 1 February 1 March 1 Discount.S 30,000 5 75,000 15,000 30,000 25.000 (75 5)$ 50,000 40,000 30,000 75,000 15,000 30,000 25,000 (859)The terms of* the installment purchase contracts require l&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date).Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) | |||
December 31.2002 2001 (in thousands) | |||
% Rate Due (a) 2002 6-7/8 2004 6.125 2006 6.45 2008 6.375 2012 6 2032 unamortized September 3 S -3uqy 1 150,000 December 15 300,000 November 10 50,000 November 1 100,000 December 31 150,000 Discount (2.973)S7AL 02$200,000 150,000 300,000 50,000 (3.856)% Rate Due City of Lawrenceburg, Indiana: 7.00 2015 April 1 S 25,000 5.90 2019 -November 1 52,000 city of Rockport, Indiana: (a) 2014 August 1 7.60 2016 March 1 6.55 2025 June 1 (b) 2025 June 1 4.90(c) 2025 June 1 city of Sullivan, Indiana: 5.95 2009 May 1 unamortized Discount I1 S 25,000 52,000 50,000 40,000 50,000 50,000 (a) A floating interest rate was determined quarterly. | |||
The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.Junior debentures outstanding were as follows: December 31.2002 2001-in thousands) 40,000 50,000 50,000 50,000% Rate Due 8.00 2026 7.60 2038 unamortized Total March 31 S 40,000 June 30 125,000 Discount (3 282)S161 71 S 40,000 125,000 (3.389)45,000 45,000 (1.664) (1 761)t3036 S1 3 (a) A variable interest rate was determined weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001.(b) In June 2001 an auction rate was established. | |||
Auction rates are determined by standard procedures every 35 days. The auction rate for 2002 ranged from 1.3% to 1.7% and averaged 1.5%. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9%to 4.9% in 2001 and averaged 3.3% during 2001.(c) Rate is fixed until June 1, 2007 (term rate bonds).Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 30,000 150,000 300,000 50,000 1.095.736 1,625,736 (8.674)51 617 06 G-1 I INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to combined Notes to Consolidated Financial statements The notes to I&M s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1.significant Accounting Policies Merger Nuclear Plant Restart Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and Sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 5 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 G-12 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America./sI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 G-13 KENTUCKY POWER COMPANY KENTUCKY POWER COMPANY Selected Financial Data Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Net Income$ 378,683 336.486 42,197 5,206 26.836$ 20,567$ 379,025 331. 347 47,678 1,248 27. 361$ 21,565$ 389,875 340.137 49,738 2,070 31.045 20,76i3$ 358,757 304.082 54,675 (327)28.918$ 2iA3A0$ 362,999 311.106 51,893 (1,726)28.491 kS _21,676 Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common Stock and Paid-in Capital Accumulated Other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$1,295,619 397, 304$1,164,676 | |||
$ 259,200 (9,451)48.269$1,128,415 384.104$ 744,311 S 999,048$ 209,200 (1,903)$1,103,064 360.648 S 742,416$1,494,543 | |||
$ 209,200 57.513 S_266,713$1,079,048 340.008$ 739.040$ 986.123$ 209,200 67.110$ 2 6,310$1,043,711 315. 546$ 728 165$ 921,3A7$ 199,200 71.,452 Si248 0-18 Lon -term Debt (a)Debt ( )3 963632$ 346-093 5-365.,782 L_3 68-838 obligations Under Capital Leases(a)Total Capitalization and Liabilities I1164. 676$1,494,543 | |||
$921,84 (a) Inc7uding portion due within one year.H-1 KENTUCKY POWER COMPANY Management s Narrative Analysis of Results of Operations KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in eastern Kentucky. | |||
KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
KPCo also sells wholesale power to municipalities. | |||
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs.KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP s settlement restructuring agreement filed with the FERC becomes operative. | |||
The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Underthe unit power agreement, there is a demand charge for the right to receive the power, which is payable even it the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity.Results of Operations Net Income for 2002 decreased | |||
$1 million or 5%.Total Revenues were flat while increases in Operating Expenses, driven by expenses related to planned outages at the Big Sandy plant, were offset by comparable gains in net nonoperating income which benefited from decreases in trading incentive compensation. | |||
Changes in Revenues wholesale Electricity* | |||
Energy Delivery*Sales to AEP Affiliates Total Increase (Decrease) | |||
Year-to-Date (dollars in milions Amount %$13 6 j!) C(34)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Revenues in 2002 were comparable to those of last year. Increased sales to retail electricity customers reflecting warmer summer weather, colder days in late 2002, and increased fuel recovery revenues were offset by lower Sales to AEP Affiliates resulting from planned outages in 2002. KPCo s decreased generation was due to scheduled maintenance resulting in lower availability in the fourth quarter.Changes in Operating Expenses Increase (Decrease) | |||
Year-to-Date (dollars in millions)Amount %S(5.6) (8)-N.M.Fuel wholesale Electricity Purchases from AEP Affiliates other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Total Operating Expenses N.M. = Not Meaningful 2.8 (5.4)12.6.7.4-E4)2 (9)56 2 5 (4)2 Fuel expense decreased in 2002 as a result of planned fourth quarter outages at the Big Sandy H-2 plant for scheduled boiler maintenance. | |||
The 800 megawatt Unit 2, representing approximately 75%of the plants generation capacity, was off-line from mid-September through the end of the year, thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to meet demand during the planned outages at the Big Sandy plant.Other Operation expense decreased in 2002 due to reduced consumption of emission allowances due to the planned outage; reduced accruals for trading incentive compensation due to reduced trading activity; and improvements in transmission expense resulting from less wholesale activity and related transmission, and an increase in AEP transmission equalization credits. Underthe AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company s peak demand and investment. | |||
A decrease in KPCo s peak demand relative to its affiliates peak demand was the main reason for the increase in transmission equalization credits. These developments were offset in part by severance expenses related to a sustained earnings initiative (see Note 11).Nonoperating Income Taxes for 2002 have increased as a result of increases in pre-tax income for the year offset in part by prior-year tax return adjustments. | |||
Other Changes Nonoperating Income for 2002 decreased as a result of AEP s previously announced plan to reduce trading activity, and decreased margins on power trading activity outside of the AEP System s traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased in 2002 as a result of decreases in trading incentive compensation. | |||
Maintenance expense increased in 2002 primarily as a result of planned power plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for planned boiler overhaul and electric plant maintenance. | |||
The Company experienced marginal increases in overhead line maintenance expense.H-3 | |||
--KENTUCKY POWER COMPANY Statements of Income Year 2002 (in Ended December 31.2001 2000 thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES$218,665 132,054 27,964 378.683 65,043 29 133,002 52,892 35,089 33,233 8,240 8.958 336,486 42,197 7,863 753 1,904 26,836 20.567$205,476 131,183 42. 366 379.02 5 70,635 86 130,204 58,275 22,444 32,491 7,854 9. 358 331, 347 47,678 10,881 8,949 684 27. 361 La25=U6$226,708 121,346 41.821 389,875 74,638 1,940 127,707 52,495 25,866 31,028 7,251 19,212 340.137 49,738 6,139 2,940 1,129 31.045 L 20,76 NET INCOME Statements of Comprehensive Income 2002 NET INCOME $ 20,5b7 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 2,225 Minimum Pension Liability (9.773)COMPREHENSIVE INCOME $1 3, ol Statements of Retained Earnings 2002 RETAINED EARNINGS JANUARY 1 $48,833 NET INCOME 20,567 CASH DIVIDENDS DECLARED 21,131 RETAINED EARNINGS DECEMBER 31 See Notes to Financial statements beginning on page L-1.Year Ended December 31, 2001 2000 (in thousands) | |||
$21,565 $20,763 (1,903)Year Ended December 31.2001 (in thousands) | |||
$57,513 21,565 30.245$A&2000$67,110 20,763 30.360 H4 KENTUCKY POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Accrued Tax Benefit Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial statements beginning on page L-1.$ 275,121 373,639 425,817 55,913 165.129 1,295,619 397.304 898.315 6.904 29.871 2,304 22,044 23,802 2,889 (192)10,817 16,127 5,301 1,253 24,320 2,127 110,792 101,976 16.818$1,164,676 S 271,070 374,116 402,537 65,059 15.633 1,128,415 384.104 744.311 6,492 29.477 1,947 20,036 16,012 3,333 (264)12,060 15,766 5,395 33,905 1,314 109,504 97.692 11,572 SL999,048 H-5 KENTUCKY POWER COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock $50 Par value: Authorized 2,000,000 shares outstanding 1,009,000 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareowner S Equity Long-term Debt Long-term Debt Affiliated Companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year -General Long- term Debt Due within one Year -Affiliated Companies Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.S 50,450 208,750 (9,451)48.269 298,018 391,632 60.000 749,650 27. 319 15,000 23,386 46,515 44,035 8,048 6,471 17,803 14. 322 175. 580 178,313 9,165 11.488 13.161$ 50,450 158,750 (1,903)48.833 256,130 176,093 75,000 507. 223 11.929 95,000 66,200 23,464 22,557 4,461 10,305 5,269 38,664 12,882 278,802 168,304 10,405 14,917 7,468 S1,164,676 H-6 KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark-to-Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities | |||
$ 20,567 33,233 9,839 (1,240)2,998 (12,267)(9,426)882 94 44,529 (11,558)(21,491)16.161 72, 321$ 21,565 $ 20,763 32,491 6,293 (1,251)(4,707)(1,454)23,694 (7,658)1,105 (22,942)(1,580)(2,762)(9,446)33, 348 31,034 3,765 (1,252)2,948 (4,376)(20,930)8,386 7,237 39,883 2,025.5,943 62,653 (62. 702)95, 377 INVESTING ACTIVITIES: | |||
construction Expenditures Proceeds From Sales of Property Net Cash Flows Used For Activities Investing (178,700)217 (178,483)(37,206)216 (36 990)(36,209)266 (35.943)FINANCING ACTIVITIES: | |||
capital contributions from Parent Company Issuance of Long-term Debt Retirement of Long-term Debt change in short-term Debt (net)change in Advances From Affiliates (net)Dividends Paid Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 50,000 274,964 (154, 500)(42,814)(21.131)106,519 357 1$947 3-2.3-04 75,000 (60,000)18,564 (30,245)3, 319 (323)2,270$ 1,947 69,685 (105,000)(39,665)47,636 (30 ,360)(57.704)1,730 540-2,270 supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000 and$28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were $22,021, $817,000 and$2,817,000 and in 2002, 2001 and 2000, respectively. | |||
see Notes to Financial Statements beginning on page L-1.H-7 KENTUCKY POWER COMPANY Statements of Capitalization December 31, 2002 2001 (in thousands) | |||
$298.018 $256.130 COMMON SHAREHOLDER S EQUITY LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Senior unsecured Notes Notes Payable Junior Debentures Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 statements beginning on page L-1.352,508 75,000 39,124 (15.000)451.632$7A9,6iQ 59,383 147,625 100,000 39,085 (95.000)251.093 5507.2_2 H-8 KENTUCKY POWER COMPANY Schedule of Lonq-term Debt First mortgage bonds follows: outstanding were as December 31.2002 2001 (in thousands) | |||
% Rate Due 6.65 2003 6.70 2003 6.70 2003 7.90 2023 Unamortized Notes payable to banks outstanding were as follows: December 31.2002 2001 (in thousands) | |||
X Rate Due 7.45 2002 September 20 S -=Junior debentures outstanding were as follows: May 1 June 1 July 1 June 1 Discount S S 15,000 15,000 15,000 14,500 il 17)First mortgage bonds were secured by a first mortgage lien on electric utility plant.Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due 8.72 2025 June 30 unamortized Discount Total 540,000 (876)539,12$40,000 (915)539 08% Rate Due (a) 2002 6.91 2007 6.45 2008 5.50 2007 4.31 2007 4.37 2007 unamortized December 31.2002 2001 (in thousands) | |||
-November 19 S -S 70,000 October 1 48,000 48,000 November 10 30,000 30,000 July 125,000 -November 12 80,400 -December 12 69,564 -Discount (456) (375)S3258S4,Z Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.At December 31, 2002, future annual long-term debt payments are as follows: (a) A floating interest rate is determined monthly. The rate December 31, 2001 was 4.3%.Notes payable to parent company were as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 15,000 60,000 322,964 70.000 467,964 (1.332)S466,-632% Rate Due 4.336 2003 6.501 2006 December 31.2002 2001 (in thousands) | |||
$15,000 S15,000 60.000 60.000 S75,00 57,0 May 15 May 15 H-9 KENTUCKY POWER COMPANY Index to combined Notes to Financial statements The notes to KPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1.Significant Accounting Policies Merger Rate Matters Effects of Regulation Commitments and Contingencies Guarantees Sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 6 Note 7 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 H-10 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 H-I 1 OHIO POWER COMPANY OHIO POWER COMPANY Selected Financial Data 2002 Year Ended December 3 2001 2000 (in thousands) | |||
.INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable To Common stock$2,113,125 1.814,796 298,329 5,376 83. 682 220,023 220,023 1.258$2,098,105 1.857, 395 240,710 18,686 93.603 165,793 (18. 348)147,445 1.258$ 146,187$2,140,331 1.913. 504 226,827 (5,004)119,210 102,613 (18.876)83,737 1.266$ 82,471 1999$1,978,826 1.689.997 288,829 7,000 83.672 212,157 212,157 1,417 LI210,740 1998$2,105,547 1,816.175 289,372 588 80,035 209,925 209,925 1.474 L 20845 2002 December 31, 2001 2000 (in thousands) | |||
-A -A ----BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$5,685,826 2.566.828$5,390,576 2.452 571$5,577,631 2.764.130$2.813 .50 361397.5$5,400,917 2.621.711$2 779,206$4. 675,5 1998$5,257,841 2,461.376$2,796,465 | |||
$4,344,68$4.457.032,93SiIM Common stock and Paid-in Capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common Shareholder's Equity$ 783,684 (72,886)522.316$ 783,684 (196)401.297$ 783,684 398.086 S1A8181Z0$ 783,577 587.424$ 783,536 587. 500 Cumulative Preferred stock: Not subject to Mandatory Redemption | |||
$ 16,648 subject to Mandatory Redemption (a) 8.850 Total Cumulative Preferred stock $ 2549 Long-term Debt (a) $1,067,314 obligations under capital Leases (a) $&65,_626 Total capitalization and Liabilities | |||
$4,457,03$ 16,648 8.850$ 16,648 8.850$ 16,937 8.850$ 17,370 11,850 SZ5__M 25.4982~2~ | |||
S fL8--6&66$6.193,975 t$A__42, 635$4,675,159 (a) Including portion due within one year.1-1 | |||
-OHIO POWER COMPANY Management s Discussion and Analysis of Results of Operations Ohio Power Company (OPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 702,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
OPCo also sells wholesale power to municipalities and cooperatives. | |||
The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each company's percentage share of AEP Power Pool revenues and costs.Results of Operations Income Before Extraordinary Item increased$54 million or 33% in 2002 mainly due to reductions in operating expenses, predominantly fuel, and interest charges.Income Before Extraordinary Item increased$63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI)program recorded in 2000. In February 2001 the U.S. District Court forthe Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP s consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net Income was also favorably impacted by the growth in and strong performance by the wholesale business. | |||
The effects of the COLI decision in 2000 and favorable wholesale business in 2001 were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the economic downturn.Operating Revenues Operating Revenues increased 1% in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. | |||
Changes in the components of Operating Revenues were: Increase (Decrease) | |||
From Previous Year (Dollars in Millions)2002 2001 Amount % Amount %Retail* $ 11 2 S(66) (8)wholesale Marketing 10 5 (19) (8)unrealized MTM 2 8 33 N.M.Other 1 1 (4) (5)Total wholesale Electricity* | |||
24 2 (56) (5)Energy Delivery* | |||
37 7 85 18 Sales to AEP Affiliates (46) (9) (71) (12)Total SL15 1 VA42) (2)* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 39%. For the fall season, heating degree days increased 32%. This 1-2 reflects a return to more normal weather conditions since 2001 weather was abnormally mild. Sales to AEP Affiliates decreased due to a 15% decrease in price, reflective of lower average fuel cost, while MWH sales rose slightly.Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool. This was the result of an affiliate being able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000.Operating Expenses Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel. Operating Expenses in 2001 also decreased 3%. This reduction was the result of lower Fuel and Income Taxes partially offset by amortization of transition regulatory assets.due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate s two nuclear units returning to service.Wholesale Electricity Purchased Power expense increased in 2002. This was the result of a 11% increase of MWH sales, partially offset by a decrease in price. In 2001 the increase was due to increases in MWH purchases from third parties because of the non-availability of associated nuclear power for resale to wholesale customers and to meet internal demand.AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18%increase of MWH purchased from affiliates with a slight decrease in the average price.The increase for 2001 was also a result of increased purchases through the AEP Power Pool.Changes in the Expenses were: Fuel wholesale Electricity Purchased Power AEP Affiliates Purchased Power Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes Total operating Expenses components of Operating Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Amount % Amount %Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Spom plants, and boiler inspections at the Amos and Cardinal Plants.S C In 2001, the commencement of amortization 102) (15) 5(85) (11) of transition regulatory assets in connection 4 6 is 30 with the transition to customer choice and market-based pricing of retail electricity supply 8 14 12 23 under Ohio deregulation accounted for the 16 4 (4) (1)(6) (4) 18 15 significant increase in Depreciation and 9 4 84 54 Amortization expense.12 SLU4)10 12 (2)(10)(86)(6)(46)(3)The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWH generated. | |||
The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal.Fuel expense decreased 11 % in 2001 mainly The 2002 increase in Taxes Other Than Income Taxes is the result of increases in state excise tax created from a change in the base tax calculation. | |||
The decrease in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax.Income Taxes increased in 2002 due to an increase in both federal and state tax 1-3 | |||
-expenses. | |||
Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis.State taxes increased predominately as a result of the State of Ohio s tax legislation revision involving utility deregulation. | |||
Income Taxes decreased in 2001 due to an unfavorable ruling in AEP s suit against the government over interest deductions claimed relating to AEP s COLI program which was recorded in 2000 and a decrease in pre-tax book income.Nonoperating Income and Nonoperating Expense The major reason for the decrease in Interest Charges in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. | |||
Extraordinary Loss In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. | |||
In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.Nonoperating Expenses decreased during 2002 due to reductions in variable incentive compensation expenses associated with wholesale trading.Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of an increase in the level of trading activity outside of the AEP System s traditional marketing area.The 2002 increase in Nonoperating Income Tax Expense is a result of the favorable tax benefit from the sale of the Ohio Coal companies in 2001. This event also caused the decrease for 2001.Interest Charges The 2002 decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.1-4 OHIO POWER COMPANY Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: Wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (See Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK$1,058,250 589,673 465.202 2,113.125 584,730 67,385 71,154 416,533 136,609 248,557 176,247 113.581 1.814.796 298,329 51,953 28,567 18,010 83.682 220,023 220,023 1.258$ 218,765$1,034,026 552,713 511,366 2.098.105 686, 568 63,441 62,585 400,790 142,878 239,982 159,778 101,373 1.857. 395 240,710 70,108 53,802 (2,380)93.603 165,793 (18.348)147,445 1.258$ 146.187$1,090,297 467,587 582.447 2.140.331 771,969 48,657 50,741 404,410 124,735 155,944 169,527 187.521 1.913.504 226,827 57,163 44,009 18,158 119.210 102,613 (18.876)83,737 1,266 Statements of Comorehensive Income 2002 Year Ended December 31.(in thousands) 2001 023 $147,445 $NET INCOME $2 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability COMPREHENSIVE INCOME 3 The common stock of oPco is wholly owned by AEP.See Notes to Financial statements beginning on page L-1.1-5 220, (542)(72.148)147,333 (196)$147,249 I 2000;83,737 OHIO POWER COMPANY Statement of Retained Earninqs Year Ended December 31.2002 2001 (in thousands) | |||
$398,086 147.445 545.531 2000 Retained Earnings January 1 Net Income$401,297 220,023 621,320$587,424 83,737 671. 161 Deductions: | |||
cash Dividends Declared: Common stock Cumulative Preferred Stock: 4.08% series 4.20% series 4.40% Series 4-1/2% Series 5.90% series 6.02% Series 6.35% series Total Dividends 97,746 58 96 139 439 428 66 32 99,004 142,976 271,813 58 96 139 439 428 66 32 144,234 59 96 139 442 428 66 32 273,075 Retained Earnings December 31 see Notes to Financia7 statements beginning on page L-1.MZJI-6 $AO1,291 $3-9&JO 1-6 OHIO POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES$3,116,825 905,829 1,114,600 260,153 288.419 5,685,826 2. 566.828 3.118.998 61,686 103.230 5,285 95,100 124,244 19,281 (909)87,409 85,379 92,108 12.083 519.980 568.641 84.497 SAA45 t932$3,007,866 891,283 1,081,122 245,232 165,073 5,390,576 2.452.571 2.938.005 62.303 99.706 8,848 84,694 148,563 20,409 (1,379)84,724 88,768 114,280 20,865 569.772 644.625 79.662 4A07 TOTAL ASSETS see Notes to Financial statements beginning on page L-1.1-7 OHIO POWER COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock No Par value: Authorized 40,000,000 shares outstanding 27,952,473 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity Cumulative Preferred Stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year -General Long-term Debt Due within one Year Affiliated Companies short-term Debt Affiliated Companies Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued obligations under Capital Leases Energy Trading Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 321,201 462,483 (72,886)522. 316 1,233,114 16,648 8,850 917.649 2. 176.261 227,689 89,665 60,000 275,000 129,979 170,563 145,718 12,969 111,778 18,809 14,360 61,839 80.608 1,171,288 794.387 18.748 39,702 28.957 54,45,032$ 321,201 462,483 (196)401,297 1,184,785 16,648 8,850 1.203,841 2.414.124 130, 386 300,213 131,057 176, 520 5,452 126,770 17,679 16,405 98,081 90.431 962.608 797.889 21.925 50,459 16.682$4,3-9A4-0173 1-8 OHIO POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation, Depletion and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Extraordinary Loss Mark to Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Customer Deposits Taxes Accrued Disputed Tax and Interest Related to COLI Employee Benefit and other Noncurrent Liabilities Impairment Loss change in other Assets change in other Liabilities Net Cash Flows From Operating Activities | |||
$ 220,023 248,557 46,010 (3,177)(28,693)14,571 704 3,081 8,704 7,517 (14,992)110,298 1,757 (2,233)(133.154)478.973$ 147,445 252,123 215,833 (3,289)18,348 (59,833)51,640 4,852 264 9,887 (34,284)(96,331)(392,026)79,831 (107.704)86.756 S 83,737 200,350 (65,956)(3,399)(56,869)18,876 (5,614)51,430 46,645 45,311 56,069 31,540 60,919 110,494 145,573 (439,448)359.640 639,298 INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From Sales of Property and other Investment in coal Companies Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt change in Advances From Affiliates (net)Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Decrease in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 (354,797)6,499 (348,298)(170,234)(140,000)275,000 (97,746)(1.258)(134.238)(3,563)8.848$ S5, (344,571)16,778 (32,115)(359.908)300,000 392,699 (297,858)(142,976)(1,258)250,607 (22,545)31. 393 (254,016)6,354 (247,662)74,748 (92,486)(182)(30,663)(194,918)(271,813)(1,262)(516, 576)(124,940)156.333 supplemental Disclosure: | |||
cash paid (received) for interest net of capitalized amounts was $81,041,000, $94,747,000 and$87,120,000 and for income taxes was $105,058,000, $(22,417,000) and $142,710,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were $106,000,$2,380,000 and $17,005,000 in 2002, 2001 and 2000, respectively. | |||
See Notes to Financia7 Statements beginning on page L-1.1-9 11 OHIO POWER COMPANY Statements of CaDitalization December 31.2002 2001 (in thousands) | |||
$1.233.114 S1.184.785 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 3.762,403$25 par value -authorized shares 4,000,000 call Price shares December 31, Number of shares Redeemed outstanding series 2002 (a) Year Ended December 31. December 31. 2002 2002 2001 2000 Not Subject to Mandatory Redemption-S100 Par: 4.08% $103 ---14,595 4.20% 103.20 --276 22,824 4.40% 104 --432 31,512 4-1/2% 110 --2.181 97.546 subject to Mandatory Redemption-S100 Par (b): 5.90% (c) $ ---6.02% (d) ---6.35% (d) ---1,460 2,282 3,151 9. 755 16. 648 7,250 1, 100 500 8.850 1,460 2,282 3,151 9. 755 16. 648 7,250 1,100 500 8.850 72,500 11,000 5,000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 136,633 141,544 Installment Purchase Contracts 233,340 233,235 senior unsecured Notes 397,341 396,962 Notes Payable to Affiliated company 300,000 300,000 Junior Debentures | |||
-132,100 Less Portion Due within one Year (149.665) | |||
-Long-term Debt Excluding Portion Due within one Year 917,649 1.203.841 TOTAL CAPITALIZATION 52 626 S2,414,14Z (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends.(b) sinking fund provisions require the redemption of 35,000 shares in 2003 and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due dates. shares previously purchased may be applied to the sinking fund requirement. | |||
At the company s optioni all shares are redeemable at S100 per share plus accrued and unpaid dividends with at least 30 days notice beginning on or after November 1, 2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April 1, 2003 for the 6.35% series.(c) commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. shares previously redeemed may be applied to meet sinking fund requirements.(d) Commencing in 2003 and continuing through 2007 sinking fund provisions will require the redemption of 20,000 shares each year of the 6.02% series and 15,000 shares each year of the 6.35% series, in each case at $100 per share. All remaining outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirements. | |||
See Notes to Financial Statements beginning on page L-1.1-10 OHIO POWER COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 6.75 2003 6.55 2003 6.00 2003 6.15 2003 (a) 2022 7.75 2023 7.375 2023 7.10 2023 7.30 2024 Unamortized Total April 1 S 29,850 October 1 27.315 November 1 12,500 December 1 20,000-February 10 -April 1 5,000 October 1 20,250-November 1 12,000 April 1 10,000 Discount (282)1135 633 S 29,850 27,315 12,500 20,000 5,000 5,000 20,250 12,000 10,000 (371)5141, 4A sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands)(a) Redeemed on May 10, 2002.First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 6.75 2004 7.00 2004 6.73 2004 6.24 2008 7-3/8 2038 unamortized Total July 1 $100,000 July 1 75,000 November 1 48,000 December 4 37,225 June 30 140,000 Discount (2.884)S37,4$100,000 75,000 48,000 37,225 140,000 (39263)Notes payable to parent company were as follows:% Rate Due 4.336% 2003 6.501% 2006 Total May 15 May 15 December 31.2002 2001 (in thousainds) | |||
S 60,000 S 60,000 240.000 240.000 Sa_,0 outstanding were as December 31.2002 2001 (in thousands) | |||
Junior debentures follows:% Rate Due Mason County, West Virginia: 5.45% 2016 December Marshall county, West Virginia: 5.45% 2014 July 1 5.90% 2022 April 1 6.85% 2022 June 1 Ohio Air Quality Development 5.15% 2026 May 1 unamortized Discount Total December 31.2002 2001 (in thousands) | |||
I S 50,000 S 50,000 50,000 50,000 35,000 35,000 50,000 50,000% Rate Due (a) 2025 (a) 2027 unamortized Total September 30 S -S 85,000 March 31 -50,000 Discount -(2.900)1 -si (a) Redeemed on July 24, 2002 At December 31, 2002 future annual long-term debt payments are as follows: 50,000 (1.660)12I33,34 50,000 (1.765)Under the terms of the installment purchase contracts, OPCo is required to pay amounts 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 149,665 223,000 240,000 459.475 1,072,140 4 826 1-11 OHIO POWER COMPANY Index to combined Notes to Financial statements The notes to OPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans Business segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 1-12 INDEPENDENT AUDITORS'REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying balance sheets and statements of capitalization of Ohio Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Ohio Power Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.1s1 Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 1-13 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income Preferred stock Dividend Requirements Gain on Reacquired Preferred stock Earnings Applicable to Common stock$ 793,647 708.926 84,721 (3,239)40.422 41,060 213$957,000 860.012 96,988 20 39.249 57,759 213$956,398 859.729 96,669 8,974 38,980 66,663$749,390 650.677 98,713 946 38.151 61,508 212$780,159 665.085 115,074 (91)38.074 76,909 212 213 1$ 40.848 LiZJ_.~ 1_0,A5I1 S-512% 9 6 $76-, 2002 December 31.2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$2,759,504 1.239,855$i,519,649 | |||
$1,76,69$2,695,099 1.184.443$1,510,656 | |||
$2,604,670 1.150.253$1.,454,417 | |||
$2,459,705 1,114.255$1 , 3A5,45Q 24$2,391,722 1.082.081 Total Assets$IAZ10 Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity$ 337,246 (54,473)116.474 S 399,247$ 337,246 142.994$ 480s2A0$ 337,246 137,688$ 474,934$ 337,246 139.237 S 476,483 S 337,246 142. 941 cumulative Preferred Stock: Not subject to Mandatory Redemption Preferred securities of subsidiary Trust Long-term Debt (a)$ 5. 27$LJ575000 S 75QQ0$ 545,437$ 451,129$_384,064 Total capitalization and Liabilities$1,748,911 | |||
$1.I 524, 846 S1,471,09 (a) Including portion due within one year.J-1 L. i PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Management s Narrative Analysis of Results of Operations Public Service Company of Oklahoma (PSO)is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma. | |||
PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. | |||
Wholesale power marketing activities are conducted on PSO s behalf byAEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
Results of Operations In 2002, Net Income decreased by $17 million or 29% primarily resulting from reduced wholesale margins and increased depreciation expense.Changes in Operating Expenses Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount %S(215.3) (47)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 23.3 45.7 (4.1)1.9 96 104 (3)4 5.6 7 2.1 (10.3)S(514)7 (30)(18)N.M. = Not Meaningful The decrease in Fuel expense in 2002 was primarily due to lower market prices for natural gas and fuel oil, and deferral of underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and to the amortization of previously overrecovered fuel costs.Changes in Operating Revenues Operating revenues decreased in 2002 as a result of reduced wholesale margins, a decline in fuel recovery revenue and decreases due to the interchange cost reconstruction (ICR) adjustments (see Note 6).Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount %wholesale Electricity* | |||
S(149.7) (23)Energy Delivery* | |||
13.6 5 sales to AEP Affiliates t27.3) (74)Total operating Revenues S(163) (17)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.The increase in Electricity Marketing Purchased Power expense in 2002 resulted mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices.The increase in the AEP Affiliates Purchased Power expense in 2002 resulted mainly from the ICR adjustments (see Note 6).Other Operation expense decreased in 2002 primarily due to lower transmission expenses and decreased factoring expenses due to reduced revenues.Maintenance expense increased, in 2002 largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002.Depreciation and Amortization expense increased in 2002 primarily due to the additional depreciable capitalized costs involved in repowering NortheastStation Units 1 & 2 completed in 2001.Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in ad valorem taxes.J-2 Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.Other Changes Nonoperating Expenses increased primarily due to the write-down of certain non-utility investments in 2002.J-3 | |||
--t PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Income Year Ended December 31.2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES$508,661 275,547 9,439 793,647 246,199 47,507 89,454 133,538 48,060 85,896 34,077 24.195 708.926 84,721 1,920 6,971 (1,812)40.422 ZO21 (in thousands) | |||
$658,352 261,877 36.771 957.000 461,470 24,187 43,758 137,678 46,188 80,245 31,973 34,513 860.012 96,988 2,112 1,740 352 39.249 2000$696,626 245,124 14, 64 8 956. 398 402,933 88,088 60,788 121,697 45,858 76,418 28,688 35,259 859.729 96,669 8,807 1,139 (1,306)38.980 NET INCOME GAIN ON REACQUIRED PREFERRED STOCK LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 41,060 1 213 57,759 213 ,$L5 66,663 212$ 66A S5$ 40,848 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 2000 (in thousands) | |||
$ 41,060 $57,759 $66,663 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(42)(54.431)$ (13.413)$5ZL75-9 I The common stock of P50 is owned by a wholly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-4 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Retained Eaminqs Year Ended December 31, 2002 2001 (in thousands) | |||
$137,688 57,759 2000$139,237 66,663 BEGINNING OF PERIOD NET INCOME DEDUCTIONS: | |||
capital Stock Gains Cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$142,994 41,060 (1)67,368 213$116,474 52,240 213 68,000 212$142,994 1IaL&6 The common stock of P50 is owned by a who ly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-5 It i -PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$1,040,520 432,846 990,947 206,747 88.444 2,759,504 1.239.855 1.519.649 OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS 4.481 16,774 31,687 14,139 (84)19,973 37,375 76,470 3,841 2.735 202.910$1,034,711 427,110 972,806 203,572 56.900 2,695,099 1,184.443 1,510,656 41.020 21. 354 5,795 31,144 10,905 (44)21,559 36,785 756 26,259 2.368 135. 527 REGULATORY ASSETS 26. 150 DEFERRED CHARGES 18.117 TOTAL ASSETS$1. 748. 911 See Notes to Financial statements beginning on page L-1.J-6 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CAPTTALIZATION AND LIARILTTIFS December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION: | |||
Common Stock $15 Par value: Authorized shares: 11,000,000 Issued Shares: 10,482,000 outstanding Shares: 9,013,000 Paid-in capital Accumulated Other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred stock Not subject to Mandatory Redemption Pso-obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Over-Recovered Fuel Costs Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS REGULATORY LIABILITIES AND DEFERRED CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.S 157,230 180,016 (54,473)116,474 399. 247$ 157,230 180,016 142.994 480.240 5,267 5,267 75,000 445.437 924.951 54.761 100,000 86,105 61,169 78,076 21,789 6,854 6,979 3,260 24. 957 389.189 341.396 32.201 32.611 1,581$1,776,690 75,000 345.129 905.636 7,263 106,000 123,087 72,759 40,857 21,041 9,476 18,150 7,298 31,718 12,216 442.602 296.877 33,992 49.080 13.461$1. 748, 911.J-7 | |||
--PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments to Reconcile Net Income to Net Cash from operating Activities: | |||
Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits changes in Certain Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies other Property and Investments Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement changes in Other Assets changes in Other Liabilities Net Cash From Operating Activities | |||
$ 41,060 85,896 75,659 (1,791)(3,737)996 (419)25,629 (11,296)(85,190)2,215 (6,928)122.094$ 57,759 80,245 (17,751)(1,791)21,405 (589)(2,809)(55,319)16,491 51,987 (9,120)9.351 149,859 S 66,663 76,418 25,453 (1,791)(28,826)677 7,994 89,330 (16,821)(36,798)(15,063)4,482 65.6193 165.615 INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds from Sale of Property other Items Net cash used For Investing Activities 963 (88.402)FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on cumulative Preferred stock Net cash From (used For)Financing Activities 187,850 (106,000)(36,982)(67,368)(213)(22,713)(124,520)(359)(124,879)(20,000)41,967 (52,240)(213)(30, 486)(176,851)(176.851)105,625 (20,000)1,951 (68,000)(212)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 10,979 5.795$1 6977 (5,506)11.301 8,128 3 .173 SL==I~i supplemental Disclosure: | |||
Cash paid (received) for interest net of capitalized amounts was $38,620,000, $38,250,000 and$33,732,000 and for income taxes was ($38,943,000), $38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively. | |||
See Notes to Financial statements beginning on page L-1.J-8 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
$ 399.247 $480.240 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: Cumulative | |||
$100 par value authorized redeemable at the option of PSO upon 30 days notice.Call Price December 31, Number of shares Redeemed Series 2002 Year Ended December 31, 2002 2001 2000 Not subject to Mandatory Redemption: | |||
4.00% $105.75 6 -25 4.24% 103.19 ---TRUST PREFERRED SECURITIES PSo-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of PSO, 8.00%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Less Portion Due Within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION see Notes to Financial Statements beginning on page L-1.shares 700,000, Shares outstanding December 31. 2002 44,600 8,069 4,460 807 5.267 75.000 298,079 47,358 200,000 (100.000)445.437 4,460 807 5. 267 75.000 297,772 47,357 106,000 (106. 000)345.129 J-9 | |||
--PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Lona-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 6.25 2003 7.25 2003 7.38 2004 6.50 2005 7.38 2023 unamortized April 1 July 1 December 1 June 1 April 1 Discount S 35,000 65,000 50,000 50,000 100,000 (1.921)S29Bs29 S 35.000 65,000 50,000 50,000 100, 000 (2 228)Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due (a)i 2002 (b) 2032 TOTAL December 31.2002 2001 (in thousands) | |||
November 21 S -S106,000 December 31 200 000 -520 00M 16 0 (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was $2.775%.(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) | |||
Rat Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 -December 1 S 1,000 S 1,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total$100,000 50,000 50,000 1,000 346. 360 547, 360 (1.923)545 437 Oklahoma Development Finance Authority (ODFA): 4.875 2014 -June 1 Red River Authority of Texas: 6.00 2020 June 1 Unamortized Discount Total i 33,700 33,700 12,660 12,660 (2) (3),Al 3-58 547 357 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of PSO.J-1 0 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Index to Combined Notes to Consolidated Financial Statements The notes to PSO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to P50. The combined footnotes begin on page L-1.combined Footnote Reference significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Benefit Plans Note 14 Business segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric utility Plant Note 28 Related Party Transactions Note 29 J-1 1 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiary as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 J-12 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements LOSS on Reacquired Preferred stock Earnings Applicable to Common stock$1,084,720 942.251 142,469 (309)59,168 82,992 82,992 229 Year En 2001$1,101,326 955,119 146,207 741 57, 581 ided December 31, 2000 (in thousands) | |||
$1,118,274 | |||
$989.996 128,278 3,851 59,457 _1999 971,527 824,465 147,062 (1,965)58,892 86,205 (3,011)83,194 229----1998$ 952,952 802,274 150,678 2,451 5,9135 97,994 97,994 705 89,367 72,672 89,367 72,672 229 229$ 8J39& U$ 72,443_$ --- a33 December 31, 2002 2001 2000 (in thousands) 1999 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$3,596,174 | |||
: 1. 697. 338$2 2S L67I5$ 380,663 (53,683)334,789$3,460,764 | |||
$3,319,024 | |||
$3,231,431 1,550,618 1,457,005-$i Q0,146 $1&862019$L380,616 | |||
$ 380,663$ 380,663 $ 380,663 1.384.242 ,2 16762:$ 380,663 283, 546 1998$3,157,911 1.317.057-£2 IQ -85A'25$ 380,663 296, 581$_677L244 308,915 293,989 S$_&6W5i8 | |||
$-6!A.-5i2 S-664,ZO0.11 1 LQ1 $ 4,70-1~ 2QTrust Preferred securities Long-term Debt (a)Total capitalization and Liabilities | |||
$__11O0,Q | |||
$ 110,000 A11 4 QQ00£_lUXlQQQ_$__M-t645 S& 6A45,963 A15&£$Z2 0-8,M~z$2,3Q0,676 | |||
$ 2 58 3&5102 6,162$2 Q8Z,258 (a) Including portion due within one year.K-1 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas. | |||
SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. | |||
Wholesale power marketing activities are conducted on SWEPCo s behalf by AEPSC.SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
Results of Operations In 2002, Net Income decreased | |||
$6.4 million or 7% primarily resulting from reduced margins.In 2001, Net Income increased | |||
$16.7 million or 23% resulting primarily from the favorable impact of our sharing in AEP s power marketing activities for a full year.Changes in Operating Revenues Operating Revenues decreased 2% for 2002 primarily due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation | |||
($12.6 million) and the positive impact of the interchange cost reconstruction (ICR) adjustments (see Note 6).In 2001, Operating Revenues decreased | |||
$17 million or 2% resulting from unfavorable wholesale marketing and trading conditions. | |||
Changes in Operating Expenses Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Amount % Amount X S(69) (15) S(41) (8)26 143 (40) (69)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 26 165 18 10 (8) (10)2 19 12 7-(1)3 3 15 14 (1)(8)(1)(20)(1)2 16£LI)4 60 (4)Increase (Decrease) | |||
From Previous Year (dollars in millions 2002 2001 Amount % Amount %wholesale Electricity* | |||
$(25) (4) S(21) (3)Energy Delivery* | |||
15 5 (12) (3)Sales to AEP Affiliates | |||
.7) (9) 16 26 Total operating Revenues £-1Z) (2) ILU) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Fuel expense decreased in 2002 due to a reduction in MWH generated and a decrease in the cost of fuel, primarily natural gas.Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. | |||
K-2 L.In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was mainly due to reduced prices caused by decreased electricity demand.The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in 2002 by$4.3 million. Other Operation expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other Operation expense increased also as a result of the Dolet Hills mining operation in June 2001.The 10% decrease in Maintenance expense in 2002 is primarily a result of higher storm and tree trimming related expenses in 2001.The increase in Depreciation and Amortization expense in 2002 is primarily due to the addition of Dolet Hills in June 2001, which added $3.0 million of additional expense in 2002. Depreciation and Amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. | |||
In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income. In 2001, the increase in income tax expense was primarily due to an increase in pre-tax income.K-3 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES$ 664,185 348,236 72,299 1.084,720 388,334 44,119 42,022 189,024 66,855 122,969 55,232 33,696 942.251$ 689,085 333,004 79,237 1.101.326 457,613 18,164 15,858 171,314 74,677 119,543 55,834 42,116 955.119$ 710,200 344,950 63,124 1.118.274 498,805 58,518 13,338 159,459 75,123 104,679 53,830 26,244 989, 996 OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 NONOPERATING EXPENSES 1,797 4,512 3,229 542 5,487 3,112 (1,476)NONOPERATING INCOME TAX EXPENSE (CREDIT)1,772 INTEREST CHARGES 59.168 57, 581 59.457 NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 229 S 82.e763 229 S 89,138 229 S 72.443 Consolidated Statements of Comprehensive Income 2002 Year Ended December 31.2001 2000 (in thousands) | |||
--- ---NET INCOME $82,992 $89,36 OTHER COMPREHENSIVE INCOME (LOSS): cash Flow Power Hedges (48) -Minimum Pension Liability (53.635) -COMPREHENSIVE INCOME "24.309 S___36 The common stock of SWEPco is owned by a who77y owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.7$72,672$72 f92 K-4 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31, 2002 2001 2000 (in thousands) | |||
BALANCE AT BEGINNING OF PERIOD NET INCOME$308,915 82,992 DEDUCTIONS: | |||
cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$293,989 $283,546 89,367 72,672 74,212 62,000 229 229$ 3C&4915 $s91I9&9 56,889 229 The common stock of SwEPCo is owned by a wholly owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.K-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financia7 statements beginning on page L-1.$1,503,722 575,003 1,063,564 378,130 75,755 3,596,174 1.697. 338 1.898.836 5,978 5,119 2,069 62,359 19,253 (2,128)61,741 33,539 2,865 4,388 17,851 201.937 49,233 47. 572$2,20,65$1,429,356 538,749 1,042,523 376,016 74.120 3,460,764 1.550.618 1.910,146 43.000 24,508 5,415 43,133 12,069 (89)52,212 32,527 8,839 30,139 18,716 202.961 52. 308 67, 753$2,300,676 K-6 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CAPITALIZATION AND LIABILITIES December 31.2002 2001 (in thousands) | |||
CAPITALIZATION: | |||
Common stock $18 Par value: Authorized 7,600,000 Shares Outstanding 7,536,640 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo Long-term Debt TOTAL CAPITALIZATION | |||
$ 135,660 245,003 (53,683)334,789 661,769 4,701 110,000 637.853 1.414.323 78.494$ 135,660 245,003 308.915 689,578 4,701 110,000 494,688 1. 298.967 40,109 OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year Advances from Affiliates, net Accounts Payable General Accounts Payable Affiliated Comp;Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Cont over-recovered Fuel other TOTAL CURRENT LIABILITIES ani es 55,595 23,239 62,139 58,773 20,110 19,081 17,051 3,724 17,226 34, 565 311.503 racts 150, 595 117,367 71,810 37,469 19,880 36,522 13,027 36,297 5,487 26,074 514.,528 369.78 48.714 13.,127 15,45S0 DEFERRED INCOME TAXES 341.064 DEFERRED INVESTMENT TAX CREDITS 44,190 REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 1.806 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$2,208,675 2LINJ7U K-7 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments to Reconcile Net Income to Net cash Flows From Operating Activities: | |||
Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts Changes in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accounts Payable Taxes Accrued Transmission coordination Agreement Settlement Fuel Recovery change in other Assets change in other Liabilities Net cash Flows From Operating Activities | |||
$ 82,992 122,969 (3,134)(4,524)$ 89,367 119,543 (31,396)(4,453)(1,151) (10,695)(24,371)(10,541)11,633 (17,441)17,713 24,257 12.16 210.563 (11,447)(19,578)(34,489)25,298 34,423 1,323 11, 714 169.610 S 72,672 104,679 14,653 (4,482)7,795 (1,254)22,103 43,962 (13,150)(24,406)(38,357)54,414 (37.001)201.628 INVESTING ACTIVITIES: | |||
Construction Expenditures Purchase of Dolet Hills Mining operations other Net cash Flows used For-Investing Activities (111,775)1.134 (110.641)FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt Redemption of Preferred stock Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents Cash and Cash Equivalents January 1 cash and cash Equivalents December 31 198,573 (150,595)(94,128)(56,889)(229)(103,268)(3,346)5.415 (111,725)(85,716)(411)(197.852)(595)106,786 (74,212)(229)31.750 3,508 1.907 (120,671)446 (120.225)149,360 (1)(45,595)(124,074)(62,000)(229)(82.5 39)(1,136)3.043 Supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000 and$51,111,000 and for income taxes was $60,451,000, $49,901,000 and $27,994,000 in 2002, 2001, and 2000, respectively. | |||
See Notes to Financia7 statements beginning on page L-1.K-8 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
S 661.769 $ 689.578 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 1,860,000 call Price December 31, Number of shares Redeemed series 2002 Year Ended December 31E 2002 2001 2000 Not subject to Mandatory Redemption: | |||
4.28% $103.90 ---4.65% $102.75 ---5.00% $109.00 --12 Shares Outstanding December 31. 2002 7,386 1,907 37,715 TRUST PREFERRED SECURITIES SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of SWEPCo, 7.875%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financial statements beginning on page L-1.740 190 3.771 4.701 110.000 315,420 179,183 198,845 (55.595)637. 853 11_41Mv23 740 190 3. 771 110.000 315,449 179,834S 150,000 (150. 595)494.688 K-9 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due 6-5/8 2003 7-3/4 2004 6.20 2006 6.20 2006 7.00 2007 7-1/4 2023 6-7/8 2025 unamortized February 1 June 1 November 1 November 1 Se tember Juqy 1 October 1 Discount S 55,000 40,000 5, 505 1,000 I 90,000 45,000 80 000 (1.085)S315-420 S 55,000 40,000 5,650 1,000 90,000 45,000 80,000 (1.201)Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
% Rate Due 4.50 2005 July 1 (a) 2002 March 1 Unamortized Discount December 31, 2002 2001 Otiw thousandcs-) | |||
S200,000 S --150,000_. 198;85 5) 0OO (a)A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.311%.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due DeSoto County: At December 31, 2002 future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 55,595 52,885 200,595 6,520 90,450 287.695 693,740 (292)S69344 7.60 2019 January 1 S 53,500 Sabine:$ 53,500 6.10 2018 April 1 Titus County: 6.90 2004 -November 1 6.00 2008 -January 1 8.20 2011 August 1 81,700 81,700 See Note 25 for discussion of Trust Preferred Securities issued by a wholly-owned statutory business trust of SWEPCo.12,290 12,290 12,620 13,070 17,125 17,125 Unamortized Premium SIZR-183 S 179-,3A K-10 i-SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to SWEPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to SWEPCo.The combined footnotes begin on page L-1.Significant Accounting Policies Extraordinary Items and Cumulative Effect Goodwill and other Intangible Assets Merger Rate Matters Effects of Regulation Customer choice and Industry Restructuring commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and Sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 K-1I INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generallyaccepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 K-12 COMBINED NOTES TO FINANCIAL STATEMENTS Index to Combined Notes to Financial Statements The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. | |||
The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 2. Extraordinary Items and Cumulative Effect AEP, APCo, CSPCo, OPCo, SWEPCo, TCC, TNC 3. Goodwill and Other Intangible Assets AEP, SWEPCo 4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC, TNC 5. Nuclear Plant Restart AEP, I&M 6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC 7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 8. Customer Choice and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo, TCC, TNC 9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 11. Sustained Earnings Improvement Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 12. Acquisitions, Dispositions and Discontinued AEP, OPCo, SWEPCo, TCC, TNC Operations | |||
: 13. Asset Impairments and Investment Value AEP, APCo, CSPCo, I&M, KPCo, OPCo, TCC, TNC Losses 14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 15. Stock-Based Compensation AEP 16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 17. Risk Management, Financial Instruments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo and Derivatives PSO, SWEPCo, TCC, TNC L-1 | |||
: 18. Income Taxes 19. Basic and Diluted Earnings Per Share 20. Supplementary Information | |||
: 21. Power and Distribution Projects 22. Leases 23. Lines of Credit and Sale of Receivables | |||
: 24. Unaudited Quarterly Financial Information | |||
: 25. Trust Preferred Securities | |||
: 26. Minority Interest in Finance Subsidiary | |||
: 27. Equity Units 28. Jointly Owned Electric Utility Plant 29. Related Party Transactions | |||
: 30. Subsequent Events (Unaudited) | |||
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP AEP, APCo, CSPCo, I&M, OPCo AEP AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, PSO, SWEPCo, TCC AEP AEP* CSPCo, PSO, SWEPCo, TCC, TNC AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP L-2 | |||
: 1. Significant Accounting Policies: Business Operations AEP s (the Company s)principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP s eleven domestic electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC, are SEC registrants. | |||
AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. | |||
These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. | |||
AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent, other commodities in the United States and Europe. In addition,theCompanysdomestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.International operations include supply of electricity and other non-regulated power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. | |||
We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale.The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. | |||
See Note 13 for further discussion of changes in our communications related business and other business operations announced in 2002.Rate Regulation AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. | |||
The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated bythe authorities of that country and are generally subject to price controls.Principles of Consolidation AEP s consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially controlled subsidiaries. | |||
The consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC include the registrant and its wholly-owned subsidiaries. | |||
Significant intercompany items are eliminated in consolidation. | |||
Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income forAEP and nonoperating income for the registrant subsidiaries. | |||
Basis of Accounting | |||
-As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. | |||
In accordance with SFAS 71,"Accounting for the Effects of Certain Types of Regulation, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. | |||
Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia byAPCo in June 2000, in Texas byTCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8, "Customer Choice and Industry Restructuring for additional information. | |||
Use of Estimates | |||
-The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. | |||
Actual results could differ from those estimates. | |||
L-3 Property, Plant and Equipment Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. | |||
Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. | |||
Additions, major replacements and betterments are added to the plant accounts. | |||
For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. | |||
The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses. | |||
Plants are tested for impairment as required under SFAS 144. See Note 13.Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization -AFUDC is a noncash, nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. | |||
The amounts of AFUDC for 2002, 2001 and 2000 were not significant. | |||
Effective with the discontinuance of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia, West Virginia and other non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized were not material in 2002, 2001, and 2000.Depreciation, Depletion and Amortization | |||
-Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, otherthan coal-mining property, and is calculated largely through the use of composite rates by functional class as follows: Functional Class of ProDertv Production: | |||
Steam-Nuclear Steam-Fossil -Fi red Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: | |||
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: | |||
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Annual Composite Depreciation Rates Ranges 2002 2.5% to 3.4%2.6% to 4.5%1.9% to 3.4%1.7% to 3.0%3.3% to 4.2%1.8% to 9.9%Annual Composite Depreciation Rates Ranges 2001 2.5% to 3.4%2.5% to 4.5%1.9% to 3.4%1.7% to 3.1%2.7% to 4.2%1.8% to 15.0%Annual Composite Depreciation Rates Ranges 2000 2.8% to 3.4%2.3% to 4.5%1.9% to 3.4%1.7% to 3.1%3.3% to 4.2%2.5% to 7.3%L4 The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which were as follows: Nuclear Steam Hyd ro Transmission Distribution General AEGCo APCo CSPco I&M KPCo OPCo PSO SWEPCo TCC TNC 3.4 2.5 3.5%3.4 3.2 4.5 3.8 3.4 2.7 3.4 2.6 2.8 2.9 3.4 2. 7 1.9 2.2 2.3 1.9 1.7 2.3 2.3 2.7 2.3 3.1 3.3 3.6 4.2 3.5 4.0 3.4 3.6 3.5 3.3 2.8%3.1 3.2 3.8 2.5 2.7 6.3 4.7 4.0 6.8 Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. | |||
The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages. | |||
These costs are included in the cost of coal charged to fuel expense for coal used by utility operations. | |||
Current average amortization rates are $0.32 per ton in 2002,$3.46 per ton in 2001 and $5.07 per ton in 2000.In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia. | |||
See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in 2002.Cash and Cash Equivalents | |||
-Cash and cash equivalents include temporary cash investments with original maturities of three months or less.Inventory Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. | |||
For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market.Materials and supplies inventories are carried at average cost.Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be carried atfairvalue until December31,2002, and inventory purchased from October 26 through December 31, 2002 was carried at the lower of cost or market. Effective January 1, 2003, all natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held in connection with trading operations by approximately | |||
$39 million. This change will be accounted for as a cumulative effect of a change in accounting principle. | |||
Accounts Receivable AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for certain non-affiliated utilities. | |||
On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreementwith a group of banks and commercial paper conduits. | |||
This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the companys balance sheet. See Note 23 for further details.Foreign Currency Translation | |||
-The financial statements of subsidiaries outside the U.S. which are included in AEP s consolidated financial statements are measured using the local currency as the functional currency and translated into U.S.dollars in accordance with SFAS 52 "Foreign Currency Translation | |||
.Assets and liabilities are L-5 translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on AEP s Consolidated Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual currency transaction gains and losses are recorded in income.Deferred Fuel Costs -The cost of fuel consumed is charged to expense when the fuel is burned.Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulators review and approval. | |||
The amount of deferred fuel costs under fuel clauses forAEP was $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "Effects of Regulation | |||
.We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. | |||
In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings. | |||
This is also true for certain of AEP s Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 6, "Rate Matters and Note 8,"Customer Choice and Industry Restructuring for further information about fuel recovery.Revenue Recognition | |||
-Regulatory Accountinq | |||
-The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. | |||
In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds)are recorded to reflect the economic effects of regulation by matching expenses with their recoverythrough regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period.Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made.When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. | |||
If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.Traditional Electricity Supply and Deliverv Activities | |||
-Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. | |||
Transportation and L-6 storage revenues also include the accrual of earned, but unbilled andlor not yet metered gas.Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133.Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves.Energy Marketinq and Trading Transactions In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). | |||
Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps.We use the mark-to-market method of accounting for trading activities as required by EITF Issue No.98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. | |||
For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net in revenues as unrealized gains and losses from mark-to-marketvaluations. | |||
When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. | |||
In October 2002, management announced plans to focus on wholesale markets around owned assets.All of the registrant subsidiaries except AEGCo participate in AEP s wholesale marketing and trading of electricity. | |||
For l&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash.Where this amount is recorded on the income statement depends on whether the contract s delivery points are within or outside of AEP s traditional marketing area. For contracts with delivery points in AEP s traditional marketing area, the total gain or loss realized in cash for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). | |||
For contracts with delivery points outside of AEP s traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income.Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. | |||
For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP s traditional marketing area or not determines where the contract is reported in the income statement. | |||
Physical forward trading sale and purchase contracts with delivery points in AEP s traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP s traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis.The trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in AEP s revenues until the contracts settle. When these contracts settle, the net proceeds are recorded in revenues and reverse the prior cumulative unrealized net gain or loss.APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized L-7 gains and losses, as well as the net proceeds upon settlement, in nonoperating income.The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked-to-market based mainly on AEP-developed valuation models. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Such valuation adjustments provide for a better approximation of fair value. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with AEP-developed price models.As explained above, the effect on AEP s Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP s regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. | |||
Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate. | |||
Construction Projects for Outside Parties Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. | |||
This method recognizes revenue in proportion to costs incurred compared to total estimated costs.Debt InstrumentHedging and RelatedActivities In order to mitigate the risks of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges.There were no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17 'Risk Management, Financial Instruments and Derivatives for further discussion of the accounting for risk management transactions. | |||
Levelization of Nuclear Refueling Outage Costs -In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M s Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and 'ending with the beginning of the next outage.Maintenance Costs Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.See below for an explanation of costs deferred in connection with an extended outage at l&M s Cook Plant.Amortization of Cook Plant Deferred Restart Costs -Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized | |||
$40 million each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and l&M.Other Income and Other Expenses Other Income includes non-operational revenue including area business development and river transportation, equity earnings of non-consolidated subsidiaries, gains on dispositions of L-8 property, interest and dividends, an allowance for equity funds used during construction (explained above) and miscellaneous income. Other Expenses includes non-operational expense including area business development and river transportation, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses.AEP Consolidated other Income and Deductions amortized over the life of the regulated plant investment. | |||
Excise Taxes AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. | |||
These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement. | |||
December 31, 2002 2001 2000 (in millions)OTHER INCOME: Equity Earnings Non-operational Revenue Interest and Miscellaneous Income Gain on sale of Frontera Gain on sale of Retail Electric Provider Total other Income OTHER EXPENSES: Property Taxes and Miscellaneous Expenses Non-operational Expenses Fiber optic and Datapult Exit Costs Provision for Loss -Airplane Total other Expenses S 104 S 123 187 123$ 22 71 Debt and Preferred Stock Gains and losses 25 16 2 from the reacquisition of debt used to finance-73 -domestic regulated electric utility plant are 129 --generally deferred and amortized over the S 45 S- ___ remaining term of the reacquired debt in accordance with their rate-making treatment. | |||
If debt associated with the regulated business is S 142 S 68 5 28 refinanced, the reacquisition costs attributable to 179 56 49 the portions of the business that are subject to-49 -cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the-14 term of the replacement debt commensurate with S1321 s1&z L z their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to EP System follows the SFAS 71 are reported as a Loss on Reacquired ting for income taxes as Debt, an extraordinary item on the Consolidated lAccounting for Income Statements of Operations of AEP and TCC. See iility method, deferred discussion of SFAS 145 in New Accounting | |||
'ded for all temporary Pronouncements section of this note for new book cost and tax basis treatment effective in 2003.Income Taxes -The AE liability method of accoun prescribed by SFAS 109, Taxes. Under the liat income taxes are provi differences between the I of assets and liabilities which will result in a future tax consequence. | |||
Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense.Investment Tax Credits -Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is included in interest charges.Where rates are regulated, redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistentwith the timing of its inclusion in rates in accordance with SFAS 71.L-9 Goodwill and Intangible Assets In June 2001, the FASB issued SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo.SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30,2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. | |||
We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note 3 for further discussion of our components of goodwill and intangible assets.SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually. | |||
SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1,2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. | |||
The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142.In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002.Nuclear Trust Funds Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. | |||
By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers funds and to allow those funds to earn a reasonable return. In general, limitations include:.Acceptable investments (rated investment grade or above)* Maximum percentage invested in a specific type of investment | |||
* Prohibition of investment in obligations of the applicable company or its affiliates. | |||
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. | |||
The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. | |||
Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115,"Accounting for Certain Investments in Debt and Equity Securities. | |||
Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liabilityaccount forthe nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.Comprehensive Income (Loss) -Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other, events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by L-1 0 | |||
-owners and distributions to owners.Comprehensive income (loss) has two components: | |||
net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.Components of Other Comprehensive Income (Loss) Other comprehensive income (loss) is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income (Loss) for AEP.segment as viewed by the chief operating decision-maker. | |||
See Note 16, "Business Segments for further discussion and details regarding segments.Common Stock Options At December 31, 2002, AEP has two stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 15. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. | |||
No stock-based employee compensation expense is reflected in AEP s earnings, as all options granted under these plans had exercise prices equal to or above the marketvalue of the underlying common stock on the date of grant. The following table illustrates the effect on AEP s net income (loss)and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation , to stock-based employee compensation. | |||
Foreign Currency Adjustments unrealized Losses on Securities unrealized Gain on Hedged Derivatives Minimum Pension Liability December 31, 2002 2001 2000 (in millions)S 4 S(113) S (99)(2) --(16) (3) -(595) (c ) (4)Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of December 31, 2002 and 2001 is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the year ended December 31, 2000 was zero.Year Ended December 31, 2002 2001 2000 (in millions except per share data)$ (519) S 971 $ 267 components December 31, 2002 2001 (in thousands) | |||
Net Income(Loss), as reported Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro forma net income (loss)Earnings (Loss) per share: Basic as reported Basic pro forma Diluted as reported Diluted pro forma L__)5Th57) 5.3 0 (12)S-95 LZ34 cash Flow Hedges: APCO cSPco I&M KPCo oPco PSO SWEPCo TCC TNC Minimum Pension Liability: | |||
APCO cSPco INM KPCO oPco PSO SWEPCo TCC TNC S(1,920)(267)(286)322 (738)(42)(48)(36)(15)S (340)(3,835)(1,903)(196)S-UI5) S2Z97 SO. S3_____) SIZAZg OM18 S(70,162)(59,090)(40,201)(9,773)(72,148)(54,431)(53,635)(73,124)(30,748)Earnings Per Share (EPS) AEP calculates earnings (loss) per share in accordance with SFAS No. 128, "Earnings Per Share (see Note 19). Basic earnings (loss) per common share is calculated bydividing neteamings (loss) available to common shareholders by the weighted average number of common shares outstanding during the'-period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming Segment Reporting The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business L-1 I conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. | |||
Basic and diluted EPS are the same in 2002, 2001 and 2000.AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS.Reclassification Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. | |||
This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts and Emerging Issues Task Force Topic D-43,"Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.39 .Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy.Certain additional prior year financial statement items have been reclassified to conform to current year presentation. | |||
Such reclassifications had no impact on previously reported net income.New Accounting Pronouncements recent market transactions and cash flow projections. | |||
As a result of that testing, AEP determined that there was a net transitional impairment loss, which is reported as a cumulative effect of a change in accounting principle. | |||
See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets.SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets.In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized. | |||
Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP s and SWEPCo s intangible assets.SFAS 143, "Accounting for Asset Retirement Obligations , is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured atfairvalue and is capitalized as part of the related assets capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest)will be recognized each period as an operating expense in the statement of operations. | |||
The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects l&M and TCC) and possibly other obligations. | |||
AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities.SFAS 142, "Goodwill and Other Intangible Assets, was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. | |||
In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations. | |||
The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on L-1 2 In addition, the regulated transmission and distribution entities have asset retirement obligations related to the final retirement of certain transmission and distribution lines. There are also underground storage tanks located at various sites throughout the AEP System and PCB s are contained in certain transformer rectifier sets at power plants. The amounts relating to these obligations cannot be determined because the entities are not able to estimate the final retirement dates for these facilities. | |||
In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity from recording an expense for estimated costs associated with the removal or retirement of assets that result from other than legal obligations. | |||
The SEC Staff concluded that amounts that are included in accumulated depreciation related to estimated removal costs arising from other than legal obligations should be written off as part of the cumulative effect of adopting SFAS 143 unless the company is regulated under SFAS 71.Companies regulated under SFAS 71 may continue to include removal costs in depreciation rates but must quantify the removal costs included in accumulated depreciation as regulatory liabilities in footnote disclosure. | |||
The AEP registrant subsidiaries that are regulated entities have included estimated removal costs for non-legal retirement obligations in book depreciation rates.For non-regulated entities, including certain formerly regulated generation facilities, asset retirement obligations associated with wind farms, closure costs associated with power plants in the U.K. and possibly other items will be incurred.Also the amount of removal costs embedded in accumulated depreciation is expected to result in a favorable cumulative effect adjustment to net income. However, AEP and its registrant subsidiaries have not completed their determination of the net effect of these items on first quarter 2003 results of operations upon the adoption of the provisions of this standard.In August 2001, the FASB issued SFAS 144,"Accounting for the Impairment or Disposal of Long-lived Assets which sets forth the accounting to recognize and measure an impairment loss. This standard replaced, SFAS 121, "Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of. AEP adopted SFAS 144 effective January 1, 2002.The adoption of SFAS 144 did not materially affect AEP s results of operations or financial conditions. | |||
See Notes 3 and 13 for discussion of impairments recognized in 2002 by AEP and its registrant subsidiaries, affected by SFAS 144.In April 2002, the FASB issued SFAS 145,"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections'. | |||
SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. | |||
In 2003, for financial reporting purposes AEP and TCC will reclassify extraordinary losses net of tax on TCC s reacquired debt of $2 million for 2001.In October2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17 (EITF 02-3). EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. | |||
Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by generally accepted accounting principles. | |||
The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts entered into and inventory purchased through October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus will be reported as a cumulative effect of an accounting change. Such contracts and inventory will continue to be accounted for at fair value through December 31,2002. Energycontracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133.L-1 3 Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. | |||
Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. | |||
Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses.Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows.Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. | |||
Unrealized gain or loss at inception is recognized only when the fair value of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. | |||
AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts. | |||
In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. | |||
This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). | |||
Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entitys commitment to an exit plan.SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. | |||
SFAS 146 also establishes that the liability should initially be measured and recorded at fair value.The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.In November 2002, the FASB issued Interpretation No. 45, "Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees. | |||
This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No.34. The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition. | |||
See guarantee details discussed in Note 10.In December 2002, the FASB issued SFAS No.148, "Accounting for Stock-Based Compensation-Transition and Disclosure , which amends SFAS No. 123, "Accounting for Stock-Based Compensation | |||
.SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. | |||
Underthe fair value based method, compensation cost for stock options is measured when options are issued. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation. | |||
SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options.In November2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation: | |||
A Comparison of FASB L-14 Nuclear Operating Company South Teas Procca Elecric Gcnerating Stailon PO. Box 28.9 Wdsworth, Texs 77483 September 29, 2003 NOC-AE-31659820 STI No.: 0300161 7 File No.: G20 1 OCFR50.71 (b)U. S. Nuclear Regulatory Commission Attention: | |||
Document Control Desk Washington, D.C. 20555 South Texas Project Units 1 and 2 Docket Nos.: STN 50-498; STN 50-499 Annual Financial Reports Pursuant to the requirements of 1 OCFR50.71 (b), STP Nuclear Operating Company acting on behalf of itself and for AEP Texas Central Company, the Austin Energy, City Public Service of San Antonio, and Texas Genco, LP (formerly: | |||
Reliant Energy), submits the attached current annual financial data for the South Texas Project Electric Generating Station.Should you require additional information, please contact Karen Wheaton at (361) 972-8698 or Ron Hyde at (361) 972-7992.Ron G. Hyde Supervisor, Corporate Insurance KMW Attachments: | |||
a) AEP Texas Central Company Annual Report b) AEP Texas Central Company Form 1 0-K c) Austin Energy Annual Report d) City Public Service of San Antonio Annual Report e) Texas Genco, LP Annual Report f) Texas Genco, LP Form 1 0-K g) STP Nuclear Operating Company Financial Statement pwq0)O:\HUMtANRESOURCES\INSURANCE\ANNUAL MUST DOS\2003\NRC-ANNUAL FINANCIALS (2003).DOC STP Nuclear Operating Company cc: (paper copy)NOC-AE-31659820 File No.: G20 Page 2 (electronic copy)Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011 -8064 U. S. Nuclear Regulatory Commission Attention: | |||
Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Richard A. Ratliff Bureau of Radiation Control Texas Department of Health 11 00 West 49th Street Austin, TX 78756-3189 Jeffrey Cruz U. S. Nuclear Regulatory Commission P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 A. H. Gutterman, Esquire Morgan, Lewis & Bockius LLP L. D. Blaylock City Public Service David H. Jaffe U. S. Nuclear Regulatory Commission R. L. Balcom Texas Genco, LP A. Ramirez City of Austin C. A. Johnson AEP Texas Central Company Jon C. Wood Matthews & Branscomb C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 F. H.G.R. G.R. D.S. C.RMS File Mallen, w/o Harrison, w/o Hyde, w/o Piggott, w/o Beaver N5001 N5001 N5001 N5014 N5014 N2002 AAERiICAN t ELECURJ I FP3Wly t r I r I v , I : .,-r, Ir-iiil'I i -i rwjrr I 2/'a 313/4Ic'I \ | |||
2002 -2001 C h a n g&-Net Income (Loss) (in millions) | |||
.ongoing ' -- ---~~$95.7 $1,087-, as reported'. | |||
(519) -S(l19 $971 (153.50 Earnings (Loss) Per Share *- -, --ngoing -- .-.. -S89$3.38: | |||
-(4~as reported -11 57] $3.01 (1_2 Revenues o-(in billions) | |||
-$14 6 $12.8 -i.--~Cash Dividends | |||
-$2.40 $2.40,-Year*End Clos~~~ing Stock Price 527.33 $ 43.53 -(37 Book Value'at Year-End-- | |||
$20.85 $25.547-' ~ Total Assets (in billions): | |||
*-. .$34.7 $39.3 U.S. Customers tat year-end) (in thousands)', 4,'975,. 4,930 0 Global Employment | |||
--' 22,083 -2 3,4 (4.202rportedls f (.7 per share, adjusted fbr investmnent-Value and asset smpairmenits (33 07, p;er*- share), disposition and aSSEt iniPairmrents of SEEBOARD and CitiPo'wer (134 per share) sustainedean Ings improvement initiative restrncrurng costs ($0. 16 per share), asset impairments of Texas plants ($0.08 per share) and other items (10.04 per share), offset by~ a gain on disposition of Texas REPs ($0.23 per sharte), produces ongoing earigs of $2.89 peshae 201rpred earnings of $3.01 per share. adjuste for merger costs ($0.05 per share), neofo oso Pipe Line-related Enron purchase obligations | |||
($0.08 per share), Severance accruals ($9.08 per share), nonre--curring adjustment | |||
~~for taxes other than PIT, ($0.04 per share), disposition andwrt-onf assets -($0.01 -_per share) and an-extraordinary loss from discontinuance of regulatiyacontn firgene&ration in certain, stares ($0. 16 per share), offset by. the cumulative effect ofSA 3ransitoajumet(05) pdu es'': -ongoing earnwg of $3.38 per shae .-- ..Thsdisso inldsfradloigsaeet ihin the mening of Section 2lEof the Secursies--- Exchangze Act of. 1934. These forward-looking statemnents reflect assumptions and involve a number of risks: aduncertainties. | |||
Amiong the factors, both foreign and domestic, that could cause, acnual results to differ materiallyfrom forwvard-looking statements are: electric-load andl customer growth;, abnormnal weather ri-coditions; aiva-ilable sources -of and prices kii 6oal'and gas;_ availability ofgenerating capacity; risks related &to energy trading and contrctiont under contract; the speedl and degree to which comeiinisitoued | |||
-- to our power generation business; the stiuceure and timing of a compedtitive market~ for 'electricity and its imat on prices; the abili ty to recover net regulitory assets,'other stranded costs and implementation coats-in c'onnection'with deregulation of generation in certain states; thetirniing of the im-pl'einmntstiois of AEP-'s '-resructurng plan, new legislation and government regulations; the ability to suiccessfully control costs; the ----success.o e business ventures;: | |||
international developments affectinm u oeg netet; h economic clitnAlre and growthi in our service and trading 'territories,' | |||
both dlomestic and fiorerign; th'e ability --of the, compansy to comply, with, and to successfly. | |||
c aln~reenvironmental regultions and tosuc- T cessfulfly litigate claims that the comjpn iltdteCta n rAc;inflsti6iary rns litigation con- --cerniuig _AEP'smn'erger wihCSW; changes in electricity and gas miia et prices' n neetrts lcutos in foreign currency exchange rates, and other risks and unforescen events. ---. | |||
4 | |||
==Dear Fellow Shareholders:== | |||
ast year was extremely | |||
-difficult for AEP. Due to a variety of factors, our earn-ings fell dramatically, as did our stock price. We deeply regret that our performance was far below our goals and your expectations. | |||
In response to the negative developments in 2002, we are taking decisive steps to strengthen our bal-ance sheet and put the company back on track for value growth. We remain dedicated to providing low-cost electricity, superior customer service and an attractive return to investors. | |||
A look back: Disappointing results Our utility operations performed reasonably well in 2002 despite rising costs, but the withering of wholesale markets in the U.S. and abroad cut into earnings from our wholesale operations. | |||
As I'm sure you're aware, the wholesale arena -including power generation, associated assets and related marketing activity -had been highly profitable for us the past couple of years.AEP's ongoing earnings totaled $2.89 per share in 2002 compared with $3.38 in 2001. As-reported earnings were negative $1.57 per share, down from $3.01 the previous year.-r. Q mu. Writing down the value of poorly performing investments contributed to charges of approximately | |||
$1.5 billion for 2002. Some of these write-offs, such as those related to telecommu-nications assets, were anticipated. | |||
Others, such as a $415 million charge related to our generation assets in the United Kingdom, were not. We also incurred an equity reduction of nearly$600 million because of lost value in our pension plan assets. While the latter event lowered the equity on our balance sheet, the other items also reduced the earnings on our income statement. | |||
On the positive side, despite last year's very tough market, we strengthened our balance sheet by $2 billion. We did it by selling non-core assets and issuing additional common stock and equity units. In 2002 we completed the sale of SEEBOARD, a regional electric company in the UK, and CitiPower, an Australian electricity provider. | |||
AEP's first visit to the equity market in 20 years occurred last spring.Cash proceeds of approximately | |||
$1.1 billion from thei asset sales and $990 million from the issuance of common stock and equity units were used to pay down debt.We did not attain our capitalization goal for 2002 of 45 percent equity and 55 percent debt but we expect t o-make significant progress this year. 2002 Sharehb Our long-term goal is 50 percent to 55 percent debt.A look ahead: Focus on the basics In 2003, we will focus on the basics. We are returning to a more traditional model of a regulated utility with a small commercial group dedicated to maximizing the value of .our generation fleet, which is the largest in the United States.S&P Electric A Currently, we think AEPs traditional utility Utlity Index business 1will perform at roughly the same ............... | |||
level as last year and the wholesale business will have a somewhat weaker year. We project 2003 ongoing earnings in the range of $2.20 to $2.40 per share, including the dilution from additional equity issued in this year's older Return executive management will not be paid 0 this year. In addition, we expect to pare our-5 capital expenditures forecast for this year by to $200 million, to $1.5 billion..,i,:* -15: I .;I......EP CL cE: E-c q: _CA: E0:E-E o --o a si::;.w:¢: 0..X.,-.T :0 E f: first quarter.* O Our decision to recommend a reduction in the quarterly dividend of about 40 percent......... | |||
-25 E: to our Board of Directors came after consid--30 erable analysis andw as painful but neces-sary. Reducing the dividend to a quarterly rate of 35 cents per share, starting with the.40 : J, 0 Vsecond quarter, will result im annual cash S&P lndex ;savings of $340 million. This will imrnmedi-............. | |||
ately improve retained earnings and create free cash flow to boost liquidity and pay down debt. We believe the dividend will still have significant value and produce an attractive yield.We began shedding assets to improve our balance sheet last year and anticipate that process will accelerate in--2003. Non-core assets are the most likely candidates for divestment. | |||
This will be an orderly disposition. | |||
Proceeds-will go toward debt reduction. | |||
----Our liquidity position is strong. We have $3.5 billion available in cash and credit facilities, and we had $1.2 billion in cash at the, end of last year. During 2003, we expect free cash flow of approximately | |||
$130 million after i .i : .: :: i 0 E -: ..,:: i:: E i : -: E -i i~ ~ ~ ~ ......E .....-i .E dividends are paid.- -In 2003, we aim for year-end capitalization consistent with a strong&BBB rating. We will continue to seek To bolster our balance sheet, we plan to lower costs,.. reduce the quarterly dividend, dispose of additional non-core assets, maintain our liquidity and current lines of credit,'and maximize cash flow.A company-wide cost reduction program should result in sustainable net savings in operations and maintenance costs of approximately | |||
$60 millhon when compared with 2002 actual expenditures, and more than $300 million when compared with previously projected 2003 expendi-tures. We reduced our work force by approximately 1,300 positions. | |||
Based on 2002 performance, bonuses for senior opportunities for further debt reduction and to work with the rating agencies to ensure we're addressing their concerns.:.: | |||
With deregulation at a standstill in much of our service area,.we are re-evaluating our corporate separation initiative. | |||
The legal separation of our regulated and unregulated businesses is provided for in Texas and Ohio,_where generation is deregulated and customers in most areas are able to choose their electricity supplier.However, the cost savings and benefits for all customers of a company-wide separation are now uncertain. | |||
We are exploring these issues with our regulators. | |||
Our intent is to comply'with restructuring legislation in the states that provide for a legal separation and to maintain a functional: | |||
separation elsewhere.-- | |||
w 1 1-state service territory, thanks in part to increased usage by residential customers. | |||
AEP's Texas operations were a major contributor to last year's utility-related earnings improvement. | |||
Customer ::`choice was introduced in January 2002 in most-areas of our Texas service territory. | |||
AEP's obligation to supply .retail electric providers (REPs) in that state last year con-tributed $495 million to gross margin. Sale of our affiliat-ed REPs to Centrica, a leading retail energy provider, near the end of 2002 provided immediate cash proceeds of:$146 million. The transaction includes an arrangement through 2006 that allows AEP. to share in any increased earnings opportunities that develop in the Texas retail*market, protecting us against downside exposure.Even with deregulation stalled, many of the nearly 5 mil-lion customers linked to our Wires will benefit from rate freezes in their respective states for the next severlS years.: Utility operations: | |||
Stable, predictable AEPs regulated operations generate stable, reasonably predictable revenue and earnings. | |||
They have been a steady contributor to our performance all along. The mission of our regulated business unit is to provide safe,: cost-effective and reliable service to customers. | |||
Ongoing earnings from utility operations in 2002 totaled$326 per, share, up from $39in 2001. Retail gross -margins rose $250 million in Texas, $178 million in Ohio and $91 million in other jurisdictions throughout AP's Transmission represents a significant piece of our regulated business. | |||
AEP, following Federal Energy''Regulatory Commission (FERC) guidance, continues working toward transferring functional control of its 38,000-mile transmission network to regioa transmis-sion organizations, or RTOs. -.-You may recall that AEP was among the companies deeply involved in recent years in developing a proposed for-profit RTO called the Alliance. | |||
Last spring, however, 3 FERC turned down our proposal, so we are pursuing affil-lation with PJM Interconnection for our eastern assets and the Midwest Independent System Operator in the west, 'At this point, we don't anticipate divesting our transmis-. | |||
sion assets. We project RTO-related costs of $30 million i.to $40 million in 2003. | |||
:1 0 0 0 0-c U)0 a 0.0 S S U)N C 0 N S 0 0.U U S'Li S U E Wholesale investments: | |||
Unmet expectations Our unregulated operations performed well below our projections in 2002. AEP's wholesale investments lost$45 -million or 13 cents per share. Some of these investments, such as our natural gas and barge-line holdings, contributed positively to earnings, but the UK generation we acquired in 2001 -the Fiddler's Ferry and Ferrybridge plants -posted a $59 million operating loss.The UK has proved to be a very disappointing and difficult market. The oversupply conditions worsened as the year progressed, particularly after the British gov-'ernment decided'to subsidize British Energy. The $415 million write-down of UK generation that I mentioned earlier. stems, from recent analyses showing that UK power prices won't recover to levels that will support the carrying value of the plants on our books at the original purchase price of roughly $1 billion.As I noted above, we will be looking to divest certain wholesale assets and the UK generation certainly will be considered. | |||
An even greater loss is possible in the UK in 2003. We're evaluating the best way, to reduce earnings drags and preserve shareholder value in this investment.l E Other unregulated investments not related to our whole-sale business also fired poorly and are candidates for" i-divestment. | |||
Our telecommunications business had a $36.-million operating loss. We are actively seeking buyers for this business.Energy marketing: | |||
Asset focus.Most of the output of our generating units is committed to our retail customers. | |||
The rest is marketed to other utilities and wholesale customers. | |||
Our decision to greatly scale back our energy marketing and trading operations and concentrate on' optimizing the value of our assets is reducing our risk exposure and helping to preserve our creditrratings. | |||
Net margins from trading activities declined by'$349 million last year because of our reduced activity and because earnings from trading in 2001 were exceptionally strong. C The outstanding net fair; value of trading contracts has fallen from approximately | |||
$450 million to $250 millionA:0 over the past year. The average duration of our existing:- | |||
trading book is year-end 2003 for gas and second-half 2004 for power.--0 Our risk management group continues to work closely with the trading group to ensure limits are enforced.We reduced value-at-risk limits by 50 percent last year..Environmental: | |||
Compliance and beyond::: Coal-fired generation remains AEP's mainstay. | |||
At the end of 2002, our generating capacity mix was 69 percent coal and lignite, 20 p1ercent natural gas, 8 percent nuclear and 3 percent wind, hydro and other.Use of fossilf Eels brings with it environmental expendi-'tures, but our customer prices remain among the lowest'-`in the regions where we operate.: | |||
Our ongoing program to meet federal standards to con-trol nitrogen oxide emissions'will cost an estimated | |||
;$1.3 'billion to $2 billion in capital expenditures. | |||
AEP remains a leader in policy discussions and research to address environmnental concerns. | |||
.We are actively promoting enactment of legislation to 4 .further reduce sulfur dioxide, nitrogen oxide and mercury emissions to address air quality issues' associated withL::',-'' | |||
coal-fired generation. | |||
AEP is one of the founding' members of the Chicago Climate Exchange' the first voluntary pilot program for trading greenhouse gas emission credits.We've committed to reducing our greenhouse gas emis-: sions by4 percent over the'next four years. AEP also is:: participating in a project, led by Battelle to assess ,, 0 i, 2 E i, i X , ,;~~~~~~~ | |||
.; ........................ | |||
whether deep injection of carbon dioxide into the earth is a feasible climate-change mitigation technology. | |||
.:: Commitment to improve I want to thank our employees for their hard work during: these unsettling times in the power industry. | |||
Assets are: AEP's strength, and our employees are our strongest | |||
:::: tS ..I : ... t i. A ---E.........i- | |||
----assets. Their dedication, talent and continued commit--ment to our business mission are at the heart of our plan'.~~ ~ ~ ~ ~~~~~~ .... ... .for recovery in the year ahead.::: | |||
:::- ..: -::-:: :. : Stepping up to new duties last 'year were Holly, Koep -who was named to oversee our unregulated businesses: | |||
after the departure of Eric van der Walde; nd To ..m. .....Hagan, head of our shared services organization. | |||
Tomr: succeeded Joe' Vipperman, who retired last year after more than four decades of dedicated service.Last year was indeed difficult and 2003 also holds::many challenges. | |||
But I believe the measures I have outlined will improve our performance, and we are C'committed to doing what it takes to rebuild the value of your investment. | |||
E. Lin n Draper, Jr..Chairm~an, President | |||
&Chief Executive Officer February 28, 2003....i 7:: , f iESE-E::: | |||
.E : -. -:~ ~: 7 :: ; , 0:0 a, 0 C/) | |||
2002 2001-Assets...Cash and Cash Equivalents | |||
.1224 -Energy Trading and Derivative Contracts Current ..104B ; 26 Other Current Assets:::...3,842L Property. | |||
Plant and Equipment 3ZA14 .Accumulated Depreciation and Amortization | |||
.-- 1,V3..q .... .......d.. .............. | |||
............... | |||
......... ....... ....Net Property, Plant and Equipment | |||
...2,8 V0.............. | |||
............. | |||
.............. | |||
............. | |||
......... | |||
....Regulatory Assets 2,8 Other Assets ... ..Total .... .S24.741 Capitalization and Liabilities | |||
.. .Energy.Trading and Derivative Contracts Current:~. | |||
.$1,4$17 Other Current Liabilities 8,4 ..t4 Long-Term Debt .Deferred Income Taxes and Investment Tax Credits'47 Minoity Interest in Financing Subst iday .79 Other Liabilities | |||
..34~a Total Liabilities Cumulative Preferred Stocks of Subsidiaries | |||
.14 0: Common Shareholders' Eqluity _______Total I .... 341 1 __ _E : Full disclosure | |||
'of all Capitalization Ratio 2002 2001 o fina~ncial information o .~~~~~~~~~~~~~~0.7% | |||
.0.7%is included in the. '1 Long-Term De b-t Appendix A to the .....Proxy Statement. | |||
CiShort-Term Debt.0.U ~ ~ ~ ~ ~ Minority Equity ~~~~~~~~~~~~~~~~~~~~ | |||
32.2% -49.3% 35.8% 42.8%~' referred Stock 32 F 14.4%..:~]:* | |||
17.5%: | |||
., , '- E .- , 7 -I ., -.7 11 I " I 1- : --I r --, 1 -1 , .,, P i --1: . I ...11 I E, n .. i. Revenues Expenses: Fuel and Purchased Eniergy Mainitenianceand Other Operation | |||
:. .. .:::~~::~: | |||
Non-Recoverable Merger Costs':, .:~~~~~~~~~~~............. | |||
................ | |||
..... ......Asset Impairments | |||
:;Depreciation and Amortization | |||
.Taxes Othe r Than Income Taxes Total Expenses Other.Income | |||
...Investment Value and Other.Imnpairment Losses Other Expenses...... | |||
Income Before Interest, Preferred Dividends. | |||
Minority Interest and Income Taxes Interest, Preferred Dividends and Minority Interest Income Taxes Income Before Discontinued Oprtin, xraordinary items and Cumu lative Effect Discontinued Operations | |||
-Income (Loss) (net of tax)Extraordinary Losses (net of tax):.: Discontinu'ance of Regulatory Accounting for Generation Loss on Reacquired Debt:-Cumulative Effect of Accounting Change (net of tax)Net Income (Loss)Average Number of Shares Outstanding.. | |||
Earnings Per Share: ~.. .....Income Before Discontinued Opraions,.~~~~~~~~~~~~~~~~~~~~~~~....... | |||
Extraordinary Items and Cumulative Effect..Discontinued Operationrs. | |||
Extraordinary Losses: 1.~:: .: ,w C umulIat i ve Effect Net Income (Loss)Cash Dividends Paid Per Sha're7::- | |||
TN.M.=Not Meaningful 2002 2001.S14,55 I $12,767 f-,6,307 4,944 3,710: 10 21 7 B67~~~~~~~~. | |||
.-1,377 ~ 1,243*718: 667: 13,292 10,585 445K! 335 321 -321 j 1 87-.1,66. 2 2,330 831; 867;214 ~546 21 917 (190) ~86.1 (48): (2)S (~1) I $ 971 i3~~: 322 2 85: 0:i.26 (0.16)I (¶.57r $ 3.01 S 2.4c~ $ .40...% Change: 1.7 N.m F S C)S C)C)-u 0 S M 0 0 C,)C..0 0.0 C,)0.0.0.: w.-...11 | |||
--I 7 -: I % -1 , -" 1, --., -, -I , 1, ..-_ .- --ly .-A .., -.Jll-1 , , ., -, -i -i i,, -, -1 ; 1. I I : ", 'zi , ,_, --, '_ 1 -, 1 -% I I .7 1 1 1, _; , -., t ----.1 __ --I 1- -2002 Operating Activities | |||
-: Net Income (Loss) M .591.;NtIcm Ls):f ; ::! ............. | |||
.... ..... .. ............... | |||
........ ........... ... .... .... ..Plus: Discontinued Operations Loss (income)Net Income from Continuing Operations Depreciation and Amortization' | |||
-.. .: :.Asset Impairments Investment Value and Other Impairments ,I~~~~~~~ ............ .. .. .. .. .. .. .. .. .. ........ .................... .. .... .. .Adjustmrents for Other Noncash Items and Working Capita!l (3.. AjsmnsfrOhrNnahiesa dWrigCptl. | |||
-:. , ;................ | |||
...... ........................................... | |||
I............. | |||
... .wi : Net Cash Flows from Operating Activities i.,, ~ ~ ~ ~ ~ .... ...... ...... ....-.. .. .. .. ... .. .. ... .. .. .. ... .. .. .................... | |||
Investing Activities:. | |||
Construction Expenditures (1.. .... .................. | |||
.... ....................................................................................... | |||
.......Purchase of Gas Pipe Line Purchase of UK Generation Purchase of Coal Company:.............. ........................... | |||
............................................ | |||
.......... | |||
,......PurchaseofBargingOperations: | |||
.-: F.Purchase of Wind Generation:: | |||
Proceeds from Sale of Retail Electric Providers.~~~~~~~~~~~~~~. | |||
..................................... ........Proceeds from Sale of Foreign Investments | |||
:................................ | |||
........... | |||
..................................................................,i.i., : 1 ^ di : i:-Proceeds from Sale of U.S. Generation Net Cash Flows used for Investing Activities | |||
.E .,.,.,.,.,,,,.,.,,.,,,...,.,.,,,,............... | |||
.. ..............................- --i.. ..Financing Activities | |||
*.Fnanin.Aciviie...........::. | |||
: ....... ......... | |||
......................................... | |||
............ | |||
.... ..11..-.'.....r. | |||
Issuance ofCommon Stock .:: I-ssuance of MinorityInterest | |||
........................................... | |||
.. ...... ...... ..... ...... ...... ..... ...... ... .Issuance of Equity Unit Senior Notes I~~~~~~...................I........... | |||
..... ............................... | |||
i^.......... | |||
.,,, .... ... .....Change in Long-term Debt (net)Retirement of Cumulative Preferred Stock~:;:liRetiementof~muitive~refrredtock-T .i;0i,,e.,..........I | |||
.................................................................. | |||
.............. | |||
.. fs, Change in Short-term Debt (net)-Cagihottrebne).,'' | |||
; : .0,.......... | |||
..... ............................................ | |||
......... | |||
., l......'.... | |||
Dividen'rds Paidon Coim'mon Stock .. ..> ,. ........K.! !..* -.*- *-- *--' ---- !*-- --- *'*- .*'' ---- -'5:: .................................... | |||
......... | |||
........ ........... | |||
.. ..... .. }}}. .Other::: t,.er.. .. .. ........... | |||
............ | |||
I.............. | |||
.. ....Z_. ... ....Net Cash Flows from (used for) Financing Activities Effect of Exchange Rate Changes on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents from Continuiing Operations Beginning of Period Cash and.Cas Equivalents fo otnigOeain n fPro-:. ':Net Increase (Decrease) in Cash: and Cash Equivalents from Discontinued Operations: | |||
: .5B'' -: :-; 'Cash and Cash Equivalents from DisContinued Operations | |||
-eginning of Period Cash and Cash Equivalents from Discontinued Operations | |||
-End of Period._2001 E i.e.$+fl.:0t t:,]"jft'. | |||
N s T;eq;fsi:48-T w7S,:*--oll ,.S..:...m.:.(usi54-.''' t'1' 'f ,.g,...X, ffi;' a@t.¢ si ,,,1 b', ,=.;,. : ii ! .d... N.. _D.. -i-i _z Rl k i N I N 1 n i S: W., E.r d's is i "!] l t l:' a:.>i-r0,: 0.: U,,, C3g 0: 0 0.0 E:_E u)C" C 0`.0:.a.0.: 0 L i Ul~'E 4 srr:^ :? -:* 4:..': n ;e .i-To the Shareholders and Board of Directors:: | |||
of American Electric Power Company, Inc.:-: We have audited the consolidated balance sheets of::: American Electric Power Company, Inc.,,and its subsidiaries as of December 31, 2002 and 2001, and the related consoli-dated statements of operations, common shareholders' | |||
: .E ---: -: .:E::---; :.-- i-::f i~~~~~~. ... .... .E.::EE;: | |||
-....equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. -These consolidated financial statements and our' report thereon dated February 21, 2003, expressing an unqualified opinion (which are not included herein) are included in.. .:::: -: --:- -.:: :E :: .:E.:: -.~~~~~~~. | |||
....: .E ~fiEi. .-.-... : Appendix A to the proxy statement for the 2002 annual meeting of.shareholders. | |||
The accompanying condensed~~~~~~~~~~~~~~~~~~~~~... | |||
.... .... .... .-.consolidated financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on such condensed consolidated financial statents in relation to the complete consolidad | |||
-.statements in relation to the complete consolidated | |||
;-: S The'management of American Electric Power Company,:.: | |||
Inc., is responsible for the integrity, representations and objectivity of the information in the Company's sumrmary annual report and condensed consolidated financial state-ments. The condensed consolidated financial statements are derived from the consolidated financial statements included..in Appendix A to the proxy statement, which has been prepared in conformity with generally accepted accounting | |||
* principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. | |||
The information in other sections of this summary annual report is consistent with these statements..T:::he consolidated financial statements have been audited by Deloitte & Touche LLP, from which these condensed consolidated financial statements have been derived and whose report appears on this page. The'auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported inancial condition and results of operations. | |||
Their audit includes procedures believed by them to provide reasonable | |||
,:assurance that the financial statements are free of material::: | |||
misstatement and includes an evaluation of the Company's internal control structure over financial reporting. | |||
: .: : .-: -wq -.: Chairman, President | |||
&Chief Executive Officer .Chief Financial Officer: financial statements. | |||
In our opinion, the information set forth in the accom-:-:.:: -_ _.: _ :: ._ :: .:: ..:: : : _ :: :: :::::::_ .: : ::._...... | |||
: .:: ..::. :.. ::::-::::. | |||
panying condensed consolidated balance sheets as of December 31, 2002 and 2001, and the related condensed consolidated statements of operations and of cash flows fort:-.. .--~~~~~~~~~~~~~~~~~~~~~~~..... | |||
the years then ended is fairly stated in all material respects in relation to the basic consolidated financial statements-.-'-...:s from which it has been derived.a..e: :, :1* .>B U m U.* -u a B 0 0 N, C0 0.......... ...S S J: ..~ ~ ~ ~~~~~~~~~~~ | |||
~ ..... ..-_-~~~~~~~~~~~~~~~~w | |||
..Columbus, Ohio February 21, 2003 Board of Directors: | |||
Front row letf to right Donald G.Smith, E.R. Brooks, E. Linn Draper, Jr.,John P. DesBarres, Robert W. Fri Bac row left to right.: Donald M. Carlton, William R.Howell, Linda Gillespie Stuntz, LeonardJ. | |||
Kujawa, Richard L.Sandor, Kathryn D. Sullivan .Thomas V. Shockley, 111, Lester A. Hudson, Jr.: Dr. E. Linn Draper, Jr., 61 .-Chairman, President& Chief Executive Officer: (1992) : E.R. Brooks, 65. -Retired Chairman.a | |||
& Chief Executive Officer, Central & South West Corp..Granbury, Texas (2000) .: Dr. Donald M. Carlton, 65 Retired President& Chief Exccutive Officer, Radian International, LLC.Austin, Texas (2000) .!N. .John P. DesBarres, 63 Investor/Consultante Park City, Utah : (997) LH.N.r Robert W. Fri 67: Visiting Scholar, Resources for the FutureL Washington, D.C.(1995)?7:7-m 0 0 U, 0.0 M..0 Co..0 LU 0 0C1 William R. Howell 67 Chairman Emeritus, J.C. Penney Company, Inc.Dallas, Texas (2000) .H.P Dr. Lester A. Hudson, Jr., 63 Professor of Business Strategy, Clemson University Greenville, South Carolina:':: | |||
(18)A-DJ : : i Leonard J. Kujawa, 70 International Energy Consultant Atlanta, Georgia:: (1997) D.'-Dr. Richard L Sandor, 61 Chairman & Chief Executive Officer, Environmnental Financial. | |||
Products, LLC Chcago, Illinois (2000) Dr''f~g Thomas V. Shockley, III, 57 Vice Chairran: (2000)Donald G. Smith, 67 Chairman, President& Chief Executive Officer, Roanoke Electric Steel Corp.Roanoke, Virginia (1994) N.?- -: Linda Gillespie Stuntz, 48 Partner-: Stuntz, Davis & Staffier, P.C.Washington, D.C.(1993) "- 'Committees of the Board: The chairman is listed in ().A Audit (Carlton),. | |||
:Directors and Corporate Governance (Hudson),.-.. | |||
: Executive (Draper), Finance (Stunt), H Human Resources (DesBarres), N Nuclear Oversight (Sullivan),: | |||
Policy (Fri)Dr. Kathryn D. Sullivan, 51 President | |||
& Chief Executive Officer, Center of Science & Industry Columbus, Ohio (1997) A N.r | |||
, --r 7 , -r -e, ...-, a "'. ---7 il , 4 4. 1 .I t- :, -i _- 7 -i'. -t! E i ., ... , %American Electric P-Service Corporatior | |||
---I'ow nI:.. ~:: :. ---.. : ..: .-:.L :, : .-Office of the Chairman r Front row Iet to right: Holly K. Koeppel, E. Irnn Draper, Jr., Thomas M. Hagan, Susan Tomasky, Bac row lift to right: Robert P. Powers, Henry W. Fayne, Thomas V. Shockley, III American Electri Company. Inc.E. Linn Draper, Jr.Chairman, President Chief Executive Offi Thomas V. Shocklh Vice Chairman: c Power and Dy,Il Offic ce.Lito.icer E. Unn Draper, Jr.: Chairman, President and Chief Executive Officer Thomas V. Shockley, lli:Vice Chairman and-:'H : i;Chief Operating Officer Henry W. Fayne Executive Vice President Thomas M. Hagan --Eecutive Vice President | |||
-Shared Services Holly K. Koeppel Executive Vice President Robert P. Powers Executive Vice President | |||
-Generation | |||
-117 Susan Tomasky .:- --: Executive Vice President-Pollcy, Fiance and:.Strategic Planning, and::Assistant Secretary Melinda S. Ackerman:? | |||
Senior Vice President | |||
-Human Resources Nicholas J. Ashooh Senior Vice President-Corporate Communuications J. Craig Baker.Seniomor Vice President | |||
-Regulation and Public Polic IA. Christopher Bakken, III ,,.Senior Vice President | |||
.- -'Nuclear Operations i: .: ... .li .E'':E ..... E i !-:iL i.ver;0-3 0:0:; i,0-f; -t,;.:: :: :::::::: :: : if -:::: -:- -,* :! i: i E i.: f i -. .:.f i-D:: :S.-..::: -:.:.-:00-S't.t | |||
-::::f:: ',,' i'-....t:' T-ttT, i i :000 'l::gE: :-:: if::-i E E i: ' ;'::"* ....:!g:-t,,-*: .i-:-. :i: [-... ...: -S-.E : i t! t :,.s ' ''f' ': E .f --i 0 ;$ tiE: 'i', t-;-,.,.-;fX,,,..,404 icye'': ::... -: :.iiE--T ---fiS if -ff. -:-.tt';; -- i.E .-EE.E if i:: iL iE:EE:iE:: | |||
:E-.i.:: -....: .:. i.: i....i. i: ..---:::::::: ::::: i -" ':.':: : :E-: tiEd E ;-, i:: Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer Jeffrey D. Cross Senior Vice President, General Counsel and : Assistant Secretary. | |||
Joseph Hamrock Senior Vice President: | |||
-General Services :: Dale E. Heydlauff Senior Vice President | |||
-Governmental and Environmental Affairs Michelle S. Kalnas Senior Vice President | |||
-Supiply Chain, 'Richard E. Munczinski Senior Vice Preside'nt | |||
-Corporate Planning .:-and Budgeting: | |||
Armando A. Pe a (l}Senior Vice President | |||
-Finance and Treasurer Michael W.: Rencheck .-Senior Vice President | |||
-Technical Services:: | |||
m William L Sigmon, Jr.:-: Senior Vice President | |||
-:: 0 Fossil and Hyro H.Generation | |||
-Scott N. Smith -Senior Vice President | |||
.-. : W and Chief Risk Officer:0 3 03-........ .-(-,....::.....L- | |||
-- i i t i O* iE i,, E iSE, i .:: i -:_:~Henry W. Fayne Vice President Armando A. Pe a.Treasurer Susan Tomasky Vice President, Secnr and Chief Financial Joseph M. Buonaii ,.-1 ,, , ...E Controller and..Chief Accounting 0 | |||
I i.','I I % -.I .I"" " n-, .;_ -.1 : fil, .,-,R 2-71N7-30, _,_-:,_1_Annual Meeting -The 96th annual meeting of shareholders of American Electric Power Company will be held at 9:30 a-m.Wednesday, April 23, 2003, at The Ohio State University's Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio. Admission is by ticket only. To obtain a ticket, please note the instructions in the Notice of Annual Meeting mailed to shareholders or call the Company. If you hold your shares through a broker, please bring proof of share ownership as of the record date.Shareholder Inquiries | |||
-If you have questions about your account, contact the Company's transfer agent, listed below. You should have your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the shareholder's approval or appropriate documents. | |||
Transfer Agent & Registrar EquiServe Trust Company, N.A.(formerly First Chicago Trust Company of New York)P.O. Box 43069 Providence, RI 02940-3069 Telephone Response Group: 1-800-328-6955 Internet address: www.equiserve.com Hearing Impaired #: TDD: 1-800-952-9245 Internet Access to Your Account -If you are a registered shareholder, you can access your account information through the Internet at www.equiserve.com. | |||
Information about obtaining a password is available toll-free at 1-877-843-9327. | |||
Replacement of Dividend Checks -If you do not receive your dividend check within five business days after the dividend'pay-ment date, or if your check is lost, destroyed or stolen, you should notify the transfer agent for a replacement. | |||
Lost or Stolen Stock Certificates | |||
-If your stock certificate is lost, destroyed or stolen, you should notify the transfer agent immediately so a 'stop transfer' order can be placed on the missing certificate. | |||
The transfer agent then will send you the required documents to obtain a replacement certificate. | |||
Address Changes -It is important that we have your current address on file so that you do nor become a lost shareholder. | |||
Please contact the transfer agent for address changes fbr both record and dividend mailing addresses. | |||
We also can provide automatic seasonal address changes.Stock Transfer -Please contact the transfer agent if you have questions regarding the transfer of stock and related legal requirements,. | |||
-Dividend Rei'nvestment and Direct Stock Purchase Plan -A Dividend Reinvestment and Direct Stock Purchase Plan is avail-able to all investors. | |||
It is an' economical and convenient method of purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent... i Direct Deposit of Dividends | |||
-The Company does offer electronic deposit of your dividends. | |||
Contact the transfer agent for details.Stock Held in Brokerage Account ('Street Name') -When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker's name or 'street name.' AEP does not know the identity of idivdual shareholders who hold their shares in this manner, we simply know that a broker holds a certain number of shares which'may be for any number of customers. | |||
If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any questions you may have about your account should be directed to your broker.How to Consolidate Accounts -If you want to consolidate your separate accounts into one account, you should contact the transfer agent to obtain the necessary instructions. | |||
When accounts are consolidated, it' may be necessary to reissue the stock certificates. | |||
;; C X .,. .. .-....- ' --A. ..f: .- .- ..... ... E i ! : ; A :. : .How to Eliminate Duplicate Mailings -If you want to maintain more than one account but eliminate additional mailings of annual reports, you may do so by contacting the transfer agent, indicating the names you wish to keep on the mailing list for annual reports and the names you wish to delete. This will affect only these mailings; dividend checks and proxy materials will continue to be sent to each accountI: | |||
IdE i-Stock Trading -The Company's common stock is traded princi-pally on the New York Stock Exchange under the ticker symbol.AER AEP stock has been traded on the NYSE for 54 years.Taxes on Dividends -The Company paid $2.40 in cash dividends in 2002, all of which' are taxable for federal income tax purposes.AEP has paid consecutive quarterly dividends since 1910.Shareholder Direct -An array of timely recorded messages.about AEP, including dividend and earnings information and recent news releases, is available from AEP Shareholder Direct at 1-800-551-lAEP (1237) anytime day or night. Hard copies of information can be obtained via fax or mail. Requests for annual reports, 10-K's, 10-Q's, Proxy Statements and Summary Annual I Reports should be made through Shareholder Direct.Financial Community Inquiries | |||
-Institutional investors or secunities analysts who have questions about the Company;should direct inquiries to Bette Jo Rozsa, 614-716-2840, bjrozsa@aep.com, orJulie Sloar, 614-716-2885, jsloat@aep.com; individual shareholders should contact Kathleen Kozero, : 614-716-2819, klkozero@aep.com, or April Dawson, 614-716-2591 addawson aep.com.Internet Home Page -Information about AEP, including financial documents, SEC filings, news releases and customer service information, is available on the Company's home page,:, on the Internet at www..aep.coml | |||
.Annual Report and Proxy Materials | |||
-You can receivei: future annual reports, proxy statements and proxies electronically rather than by mail; if you are'a registered holder, log on to wvww.econsent.comlaep.- | |||
If you hold your shares in street name, contact your broker.-7IEI:Ii; Cd, M E: E.Li) | |||
WA MT NO MN i ME OR I0 C.. : F:ti'S .C) N- W I-l, So WY M!VT NH NY I MA CT RI NJ[A NE NV UT MD CA co NM KS MO DE ,, , -OKDr TN NC AZ AR LA SC MS AL GA-AEP service area-; Transmission lines FL More than 42,000 megawatts of electric generating capacity, including the largest generation fleet in the U.S.-38,000 circuit miles of transmission lines 186,000 miles of distribution lines:.128 billion cubic feet of gas storage 6,400 miles of natural gas pipeline 7,000 rail cars 1,800.barges and 37 tug boats .Annual coal production capability of 10 million tons American Electric Power owns and operates more than;'42,000 megawatts of generating capacity in the United.States and select international markets and is the largest electricity generator in the U.S. AEP is also one of the largest electric utilities in the United States, with almost 5 million customrers linked to AEP's electricity transmission and distribution grid. Those customers are located in 11 states -Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio Oklahoma, Tennessee, Texas, Virginia and West Virginia. | |||
The company's distribution service area:*6covers 197,500 square miles., Outside the United States, AEP holds interests in the United Kingdom, Australia, Brazil, China, Mexico and the Pacific Regions bs i C Ohio..AEP is based in Columbus, Ohio. 4 f 0;>z -z e | |||
2002 Annual Reports American Electric Power Company, Inc.AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Audited Financial Statements and Management s Discussion and Analysis AMERICAN ELECTRIC POWER AEPh.rnfefica:s EnewTy Partner' Contents Page Glossary of Terms i Forward Looking Information iv AEP Common Stock and Dividend Information v American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Operations A-9 Consolidated Balance Sheets A-10 Consolidated Statements of Cash Flows A-12 Consolidated Statements of Common Shareholders Equity and Comprehensive Income A-13 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-14 Schedule of Consolidated Long-term Debt of Subsidiaries A-15 Index to Combined Notes to Consolidated Financial Statements A-1 6 Independent Auditors' Report A-17 Management's Responsibility A-18 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Combined Notes to Financial Statements B-8 Independent Auditors' Report B-9 AEP Texas Central Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income C-5 Consolidated Statements of Retained Earnings C-6 Consolidated Balance Sheets C-7 Consolidated Statements of Cash Flows C-9 Consolidated Statements of Capitalization C-1 0 Schedule of Long-term Debt C-1I Index to Combined Notes to Consolidated Financial Statements C-13 Independent Auditors' Report C-1 4 AEP Texas North Company Selected Financial Data D-A Management's Narrative Analysis of Results of Operations D-2 Statements of Operations and Statements of Comprehensive Income D-4 Statements of Retained Earnings D-5 Balance Sheets D-6 Statements of Cash Flows D-8 Statements of Capitalization D-9 Schedule of Long-term Debt D-1 0 Index to Combined Notes to Financial Statements D-1 1 Independent Auditors' Report D-1 2 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Discussion and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income E-5 Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-1 0 Schedule of Long-term Debt E-1 I Index to Combined Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-1 3 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Narrative Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income F-4 Consolidated Statements of Retained Earnings F-5 Consolidated Balance Sheets F-6 Consolidated Statements of Cash Flows F-8 Consolidated Statements of Capitalization F-9 Schedule of Long-term Debt F-1 0 Index to Combined Notes to Consolidated Financial Statements F-11 Independent Auditors' Report F-1 2 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data G-1 Management's Discussion and Analysis of Results of Operations G-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income G-5 Consolidated Statements of Retained Earnings G-6 Consolidated Balance Sheets G-7 Consolidated Statements of Cash Flows G-9 Consolidated Statements of Capitalization G-10 Schedule of Long-term Debt G-1I Index to Combined Notes to Consolidated Financial Statements G-12 Independent Auditors' Report G-13 Kentucky Power Company Selected Financial Data H-1 Management's Narrative Analysis of Results of Operations H-2 Statements of Income, Statements of Comprehensive Income and Statements of Retained Earnings H4 Balance Sheets H-5 Statements of Cash Flows H-7 Statements of Capitalization H-8 Schedule of Long-term Debt H-9 Index to Combined Notes to Financial Statements H-10 Independent Auditors' Report H-11 | |||
--Ohio Power Company Selected Financial Data 1-1 Management's Discussion and Analysis of Results of Operations 1-2 Statements of Income and Statements of Comprehensive Income 1-5 Statements of Retained Earnings 1-6 Balance Sheets 1-7 Statements of Cash Flows 1-9 Statements of Capitalization 1-10 Schedule of Long-term Debt 1-11 Index to Combined Notes to Financial Statements 1-12 Independent Auditors' Report 1-13 Public Service Company of Oklahoma and Subsidiary Selected Consolidated Financial Data J-1 Management's Narrative Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income J-4 Consolidated Statements of Retained Earnings J-5 Consolidated Balance Sheets J-6 Consolidated Statements of Cash Flows J-8 Consolidated Statements of Capitalization J-9 Schedule of Long-term Debt J-10 Index to Combined Notes to Consolidated Financial Statements J-1 1 Independent Auditors' Report J-1 2 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data K-1 Management's Discussion and Analysis of Results of Operations K-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income K-4 Consolidated Statements of Retained Earnings K-5 Consolidated Balance Sheets K-6 Consolidated Statements of Cash Flows K-8 Consolidated Statements of Capitalization K-9 Schedule of Long-term Debt K-1 0 Index to Combined Notes to Consolidated Financial Statements K-1 I Independent Auditors' Report K-1 2 Combined Notes to Financial Statements L-1 Registrants Combined Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters M-1 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below: Term Meaning 2004 True-up Proceeding | |||
........ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs.AEGCo .. ................... | |||
AEP Generating Company, an electric utility subsidiary of AEP.AEP .................. | |||
American Electric Power Company, Inc.AEP Consolidated | |||
.................... | |||
AEP and its majority owned consolidated subsidiaries. | |||
AEP Credit .................. | |||
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and non-affiliated domestic electric utility companies. | |||
AEP East companies | |||
............... | |||
APCo, CSPCo, I&M, KPCo and OPCo.AEPR .................. | |||
AEP Resources, Inc.AEP System or the System ....... The American Electric Power System, an integrated electric utility system, owned and operated by AEP s electric utility subsidiaries. | |||
AEPSC .................... | |||
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. | |||
AEP Power Pool .................... | |||
AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. | |||
AEP West companies | |||
............... | |||
PSO, SWEPCo, TCC and TNC.AFUDC .................... | |||
Allowance forfunds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant.Alliance RTO .. .................. | |||
Alliance Regional Transmission Organization, an ISO formed byAEP and four unaffiliated utilities (the FERC overturned earlier approvals of this RTO in December 2001).Amos Plant ................... | |||
John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.APCo ..................... | |||
Appalachian Power Company, an AEP electric utility subsidiary. | |||
Arkansas Commission | |||
............. | |||
Arkansas Public Service Commission. | |||
Buckeye .................. | |||
Buckeye Power, Inc., an unaffiliated corporation. | |||
CLECO .................. | |||
Central Louisiana Electric Company, Inc., an unaffiliated corporation. | |||
COLI .................. | |||
Corporate owned life insurance program.Cook Plant .................. | |||
The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.CPL .................... | |||
Central Power and Light Company [legal name changed to AEP Texas Central Company (TCC) effective December 2002]. See TCC.CSPCo .................... | |||
Columbus Southern Power Company, an AEP electric utility subsidiary. | |||
CSW ...... ............ | |||
Central and South West Corporation, a subsidiary of AEP (Effective January 21,2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).CSW Energy ................... | |||
CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.CSW International | |||
.................... | |||
CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States.D.C. Circuit Court .................... | |||
The United States Court of Appeals for the District of Columbia Circuit.DHMV ................... | |||
Dolet Hills Mining Venture.DOE .................. | |||
United States Department of Energy.ECOM ................... | |||
Excess Cost Over Market.ENEC .................... | |||
Expanded Net Energy Costs.EITF .................... | |||
The Financial Accounting Standards Board s Emerging Issues Task Force.ERCOT .................. | |||
The Electric Reliability Council of Texas.EWGs .................. | |||
Exempt Wholesale Generators. | |||
FASB .................. | |||
Financial Accounting Standards Board.Federal EPA .................. | |||
United States Environmental Protection Agency.i FERC ................ | |||
Federal Energy Regulatory Commission. | |||
FMB ..... ........... | |||
First Mortgage Bond.FUCOs ...... .......... | |||
Foreign Utility Companies. | |||
GAAP ..... ........... | |||
Generally Accepted Accounting Principles. | |||
I&M ................ | |||
Indiana Michigan Power Company, an AEP electric utility subsidiary. | |||
ICR ................ | |||
Interchange Cost Reconstruction. | |||
IPC .... ............ | |||
Installment Purchase Contract.IRS .... ............ | |||
Internal Revenue Service.IURC ................ | |||
Indiana Utility Regulatory Commission. | |||
ISO .... ............ | |||
Independent System Operator.Joint Stipulation | |||
.. ................ | |||
Joint Stipulation and Agreement for Settlement of APCo s WV rate proceeding. | |||
KPCo ................ | |||
Kentucky Power Company, an AEP electric utility subsidiary. | |||
KPSC ................ | |||
Kentucky Public Service Commission. | |||
KWH .................. | |||
Kilowatthour. | |||
LIG ................ | |||
Louisiana Intrastate Gas.Michigan Legislation | |||
................ | |||
The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.MISO .................. | |||
Midwest Independent System Operator (an independent operator of transmission assets in the Midwest).MLR ................ | |||
Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.Money Pool ........ ........ AEP System s Money Pool.MPSC ................ | |||
Michigan Public Service Commission. | |||
MTM ..... ........... | |||
Mark-to-Market. | |||
MTN ..... ........... | |||
Medium Term Notes.MW ................ | |||
Megawatt.MWH ..... ........... | |||
Megawatthour. | |||
NEIL ..... ........... | |||
Nuclear Electric Insurance Limited.NOx ................ | |||
Nitrogen oxide.NOx Rule ................ | |||
A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate.NP .................. | |||
Notes Payable.NRC ................ | |||
Nuclear Regulatory Commission. | |||
Ohio Act ................ | |||
The Ohio Electric Restructuring Act of 1999.Ohio EPA ................ | |||
Ohio Environmental Protection Agency.OPCo ................ | |||
Ohio Power Company, an AEP electric utility subsidiary. | |||
OVEC ................ | |||
Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.PCBs ................ | |||
Polychlorinated Biphenyls. | |||
PJM .................. | |||
Pennsylvania New Jersey Maryland regional transmission organization. | |||
PRP ................ | |||
Potentially Responsible Party.PSO ................ | |||
Public Service Company of Oklahoma, an AEP electric utility subsidiary. | |||
PUCO ................ | |||
The Public Utilities Commission of Ohio.PUCT .................. | |||
The Public Utility Commission of Texas.PUHCA ................ | |||
Public Utility Holding Company Act of 1935, as amended.PURPA ................ | |||
The Public Utility Regulatory Policies Act of 1978.RCRA .... ............ | |||
Resource Conservation and Recovery Act of 1976, as amended.Registrant Subsidiaries | |||
............. | |||
AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.REP ................ | |||
Retail Electric Provider.Rockport Plant ................ | |||
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and l&M.RTO ................ | |||
Regional Transmission Organization. | |||
ii SEC ............. | |||
Securities and Exchange Commission. | |||
SFAS .... ......... | |||
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.SFAS 71 ............... | |||
Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. | |||
SFAS 101 ............... | |||
Statement of Financial Accounting Standards No. 101, Accounting forthe Discontinuance of Application of Statement 71.SFAS 133 ............. | |||
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. | |||
SNF ............. | |||
Spent Nuclear Fuel.SPP ............... | |||
Southwest Power Pool.STP ............... | |||
South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an AEP electric utility subsidiary. | |||
STPNOC ..... ........ STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including TCC.Superfund | |||
............. | |||
The Comprehensive Environmental, Response, Compensation and Liability Act.SWEPCo ............... | |||
Southwestern Electric Power Company, an AEP electric utility subsidiary. | |||
TCC ............. | |||
AEP Texas Central Company, an AEP electric utility subsidiary | |||
[formerly known as Central Power and Light Company (CPL)].Texas Appeals Court ............. | |||
The Third District of Texas Court of Appeals.Texas Legislation | |||
.. ............. | |||
Legislation enacted in 1999 to restructure the electric utility industry in Texas.TNC ............. | |||
AEP Texas North Company, an AEP electric utility subsidiary | |||
[formerly known as West Texas Utilities Company (WTU)].Travis District Court ............. | |||
State District Court of Travis County, Texas.TVA ............... | |||
Tennessee Valley Authority. | |||
U. ............. | |||
The United Kingdom.UN ............. | |||
Unsecured Note.VaR ............... | |||
Value at Risk, a method to quantify risk exposure.Virginia SCC ............. | |||
Virginia State Corporation Commission. | |||
WV ............... | |||
West Virginia.WVPSC ............... | |||
Public Service Commission of West Virginia.WPCo ............. | |||
Wheeling Power Company, an AEP electric distribution subsidiary. | |||
WTU ............. | |||
West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective December 2002]. See TNC.Yorkshire | |||
............... | |||
Yorkshire Electricity Group pic, a U.K. regional electricity company owned jointly by AEP and New Century Energies until April 2001.Zimmer Plant ............. | |||
William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary. | |||
iii FORWARD LOOKING INFORMATION These reports made byAEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21 E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. | |||
Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:* Electric load and customer growth.* Abnormal weather conditions. | |||
.Available sources and costs of fuels.* Availability of generating capacity.* The speed and degree to which competition is introduced to our service territories. | |||
* The ability to recover stranded costs in connection with possible/proposed deregulation. | |||
* New legislation and government regulation. | |||
* Oversight and/or investigation of the energy sector or its participants. | |||
* The ability of AEP to successfully control its costs.* The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile.* International and country-specific developments affecting AEP's foreign investments including the disposition of any current foreign investments and potential additional foreign investments. | |||
.The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.* Inflationary trends.* Electricity and gas market prices.* Interest rates.* Liquidity in the banking, capital and wholesale power markets..Actions of rating agencies.* Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. | |||
.Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.iv AEP Common Stock and Dividend Information The quarterly high and low sales prices and the quarter-end closing price for AEP common stock and the cash dividends paid per share are shown in the following table: Quarter-end Quarter Ended High Low Closing Price Dividend March 2002 $47.08 $39.70 $46.09 $0.60 June 2002 48.80 39.00 40.02 0.60 September 2002 40.37 22.74 28.51 0.60 December2002 30.55 15.10 27.33 0.60 March 2001 $48.10 $39.25 $47.00 $0.60 June 2001 51.20 45.10 46.17 0.60 September 2001 48.90 41.50 43.23 0.60 December 2001 46.95 39.70 43.53 0.60 AEP common stock is traded principally on the New York Stock Exchange. | |||
At December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003 management recommended thatthe Company reduce dividends by approximately 40% after payment of the March 2003 dividend which was approved by the Company s Board of Directors at the current level of $0.60 per share.v AMERICAN ELECTRIC POWER COMPANY, INC.AND SUBSIDIARY COMPANIES AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES selected consolidated Financial Data Year Ended December 31, 2002 2001 2000 1999 1998 OPERATIONS STATEMENTS DATA (in millions): | |||
Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080 operating Income 1,263 2,182 1,774 2,061 2,046 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 21 917 180 869 859 Discontinued operations Income (Loss) (190) 86 122 117 116 Extraordinary Losses -(50) (35) (14) _Cumulative Effect of Accounting change Gain (Loss) (350) 18 ---Net Income (Loss) (519) 971 267 972 975 December 31. 2002 2001 2000 1999 1998 BALANCE SHEET DATA (in millions): | |||
Property, Plant and Equipment | |||
$37,857 $37,414 $34,895 $33,930 $32,400 Accumulated Depreciation and Amortization 16.173 15.310 14.899 14.266 13.374 Net Property, Plant and Equipment | |||
$22,104 $19,996 S1 5664 Total Assets $34,741 $39,297 $46,633 $35,296 $33,418 Common shareholders' Equity 7,064 8,229 8,054 8,673 8,452 Cumulative Preferred Stocks of Subsidiaries* | |||
145 156 161 182 350 Trust Preferred securities 321 321 334 335 335 Long-term Debt* 10,496 9,505 8,980 9,471 9,215 Obligations under capital Leases* 228 451 614 610 539 Year Ended December 31. 2002 2001 2000 1999 1998 COMMON STOCK DATA: Earnings per Common share: Before Discontinued operations, Extraordinary Items and cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70 Discontinued Operations (0.57) 0.26 0.38 0.36 0.36 Extraordinary Losses -(0.16) (0.11) (0.04) -cumulative Effect of Accounting change (1.06) 0.06 ---Earnings (Loss) Per share (1.5) $3.1 $0-83 $ 3.03 $_3.0 Average Number of shares Outstanding (in millions) 332 322 322 321 318 Market Price Range: High $ 48.80 $51.20 $48-15/16 | |||
$48-3/16 $53-5/16 Low 15.10 39.25 25-15/16 30-9/16 42-1/16 Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16 cash Dividends on Common** $ 2.40 $2.40 S2.40 $2.40 $2.40 Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%Book value per share $20.85 $25.54 $25.01 $26.96 $26.46*Including portion due within one year. Long-term Debt includes Equity unit senior Notes.**Based on AEP historical dividend rate. See "Common stock and Dividend Information (on page v) regarding the potential reduction of future dividends. | |||
A-1 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Managements Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S. We provide generation, transmission and distribution service to almost five million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. | |||
We have a vast portfolio of assets including: | |||
* 38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in our market areas.4,000 megawatts of generating capacity in the U.K., a countrywhich is currently experiencing excess generation capacity* 38,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S.* 186,000 miles of distribution lines that support delivery of electricity to our customers premises a Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity)* 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of gas storage facilities Business Strategy We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets. We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business.Through our utility operations focus, we intend to be the energy and low cost generation provider of choice. We have ample generation to meet our customers needs.We have a cost advantage resulting from AEP s long tradition of designing, building and operating efficient power plants and delivery networks. | |||
Our customers continue to show top quartile level of satisfaction. | |||
We provide safe and reliable sources of energy.Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. | |||
Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors. | |||
We are addressing many challenges in our unregulated business. | |||
We have already substantially reduced our trading activities. | |||
We have written down the value of several investments to reflect deterioration in market conditions. | |||
We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy. | |||
We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling. | |||
Transition rules for Michigan and Virginia do not require legal separation. | |||
Deregulation is no longer an expectation in the foreseeable future in the other states where we operate.Our strategy for the core business of utility operations is to:.Maintain moderate but steady earnings growth* Maximize value of transmission assets and protect our revenue stream in an RTO membership environment | |||
* Continue process improvement to maintain distribution service quality while, at the same time, further enhancing financial performance | |||
* Optimize generation assets through increased availability and sale of A-2 excess capacity Manage the regulatory process to maximize retention of earnings improvement while providing fair and reasonable rates to our customers We remain very focused on credit quality and liquidity as discussed in greater detail later in this report.We are committed to continually evaluating the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and sustainable shareholder value. Any investment dispositions could affect future results of operations, cash flows and possibly financial condition. | |||
2002 Overview 2002 was a year of rapid and dramatic change for the energy industry, including AEP, as the wholesale energy market quickly shrank and many of its participants exited or significantly limited future trading activity.Investors lost confidence in corporate America and the economy stalled. Investors demand for stability, predictable cash flows, earnings, and financial strength have replaced their demand for rapid growth.Our wholesale business did not perform well.We had significant losses in options trading in the first half of the year and new investments performed well below our expectations. | |||
We focused on financial strength by:* Issuing approximately | |||
$1 billion in common stock and equity units.Retiring debt of approximately | |||
$3 billion through the sale of two foreign retail utility companies in the U.K.(SEEBOARD) and Australia (CitiPower) | |||
* Establishing a cash liquidity reserve of$1 billion at year-end See Financing Activity in Managements Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters in section M for an overview of all changes to capital structure. | |||
We also focused on:* Implementing an enterprise-wide risk management system* Completing a cost reduction initiative which we expect to result in sustainable net annual savings of more than $200 million beginning in 2003* Eliminating or reducing future capital requirements associated with non-core assets We have redirected our business strategy by:* Scaling back trading activities to focus principally on supporting our core assets* Selling our Texas retail business.Proposing the sale of a significant portion of the Texas unregulated generation assets Outlook for 2003 We remain focused on the fundamental earnings power of our utility operations, and we are committed to strengthening our balance sheet. Our strategy for achieving these goals is well planned:* First, we will continue to identify opportunities to reduce our operations and maintenance expense.* Second, we will find opportunities to reduce capital expenditures. | |||
* Third, management recommended a 40% reduction in the common stock dividend beginning in the second quarter to a quarterly rate of $0.35 per share. This will result in annual cash savings of approximately | |||
$340 million and should improve our retained earnings as well as create free cash flow to improve liquidity and pay-down outstanding debt.* Fourth, we plan to evaluate and, where appropriate, dispose of non-core assets. Proceeds from these sales will be used to reduce debt..Fifth, we will continue to evaluate the potential for issuing additional equity to further strengthen our balance sheet and maintain credit quality.We remain committed to being a low cost provider of electricity, to serving our A-3 customers with excellence and to providing an attractive return to investors. | |||
We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets.Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters. We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors. | |||
Results of Operations In 2002, AEP s principal operating business segments and their major activities were:* Wholesale: | |||
o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity trans-mission o Domestic electricity distri-bution* Other Investments o Energy Services Net Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased | |||
$896 million or 98% to $21 million in 2002 from $917 million in 2001. The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. | |||
In 2002, the Company s Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3).Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP s wholesale marketing business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. The effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron s bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.Our wholesale business has been affected by a slowing economy. Wholesale energy margins and energy use by industrial customers declined in 2002 and 2001.Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO.Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues in 2002 and 2001.Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001.A-4 Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be more volatile. | |||
See 'Market Risks section for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. | |||
Revenues Increase AEP s total revenues increased 14% in 2002 and 15% in 2001. The following table shows the components of revenues: For The Year Ended December 31 2002 2001 2000 (in millions)WHOLESALE: | |||
Residential | |||
$ 3,713 commercial 2,156 Industrial 1,903 other Retail customers 385 Electricity Marketing (net) 2,227 unrealized MTM Income-Electric 136 other 1,397 Less: Transmission and Distribution Revenues Assigned to Energy Delivery* | |||
(3.551)wholesale Electric 8.366 S 3,553 2,328 2,388 S 3,511 2,249 2,444 419 414 802 1,073 210 38 632 837 has had a major effect on the volume of wholesale power marketing especially in the short-term market.The increase in 2002 in wholesale revenues resulted from a 27% increase in trading volume associated with Wholesale Electricity which was offset by a continuing decrease in gross margins which began in the fourth quarter of 2001, and an increase in residential sales as a result of favorable weather conditions in the third quarter 2002.In addition OtherWholesale electric revenues increased due to the mid-year 2001 acquisition of barging and coal mining operations as well as the recognition of revenues for generation projects completed for third parties. The increase in 2002 Wholesale Gas revenues resulted from a full year of HPL operations compared to a partial year from our acquisition date in July 2001, offset by a decrease in the results from financial trading and MTM unrealized losses.Other Investments revenue decreased in 2002 due to the elimination of factoring of accounts receivable of an unaffiliated utility.Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. | |||
Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 1).Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in 2001. This decrease was due to the economic slow down which began in late 2001. Sales to residential customers rose 5%due to weather related demand in 2002. The economic slow down reduced demand and wholesale prices especially in the latter part of 2001.i (3.356) (3.174)6,97 7,392 Gas Marketing (net) 3,021 2,274 unrealized MTM Income (Loss)-Gas (399) 47 wholesale Gas 2.622 2.321 TOTAL WHOLESALE 10.988 9.297 310 132 442 7,834 DOMESTIC ELECTRICITY DELIVERY: Transmi ssi on Distribution TOTAL DOMESTIC ELECTRICITY DELIVERY OTHER INVESTMENTS 922 1,029 1,009 2.629 2,327 2.165 3.551 3,356 3,174 16 114 105 TOTAL REVENUES S14,5m 11.77 ,*Certain revenues in the wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.The level of electricity transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC s introduction of a greater degree of competition into the wholesale energy market A-5 I Ooeratina ExDenses Increase Changes in the components of operating expenses were as follows: Inc Fr Amour Fuel and Purchased Energy: Electricity | |||
$ 959 Gas 404 Maintenance and other operation 303 Non-recoverable Merger Costs (11)Asset Impairments 867 Depreciation and Amortization 134 Taxes other Than Income Taxes 51 Total:rease (Decrease) tom Previous Year 2002 200.(in millions)it % Amount %43.7 S(1,275)(36.7) 14.7 2,339 570.5 8.2 i (52.4)N.M.228 6.5 (182) (89.7)CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected, merger costs declined in 2001 and 2002 after the merger was consummated. | |||
In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling $1.4 billion (consisting of approximately, $866.6 million related to asset impairments, $321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included: 2002 Pre-Tax Estimated Loss (in millions)10.8 152 13.9 7.6 (16) (2.3)25.6 51.246 13.3 The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. | |||
Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001. The return to service of the Cook Plants two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation. | |||
The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001.The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full years expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. | |||
The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001.Maintenance and Other Operation expense rose in 2001 mainly as a result of additional traders incentive compensation and accruals for severance costs related to corporate restructuring. | |||
With the consummation of the merger with Asset Impairments Held for sale Asset Impairments Held and used Investment value Losses S 483.1 651.4 291.9 Total Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations. | |||
The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service.Depreciation and Amortization expense increased in 2001 primarily as a result of the A-6 commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and WestVirginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in Property, Plant and Equipment. | |||
Taxes OtherThan IncomeTaxes increased in 2002 due to a full year of state excise taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in Texas partly offset by the effect of Texas one-time 2001 assessments and decreased gross Texas receipts taxes due to deregulation. | |||
Interest. | |||
Preferred Stock Dividends, Minority Interest The decrease in Interest in 2002 was primarily due to a reduction in short-term interest rates and lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates offset in part by an increased amount of long-term debt outstanding. | |||
Interest expense decreased 15% in 2001 due to the effect of interest paid to the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.Minority Interest in Finance Subsidiary increased substantially in 2002 because the distributions to minority interest were in effect for the entire year. In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest. | |||
The minority interest was only in effect during the last four months of 2001.Other Income/Other Expenses This increase was primarily caused by an increase in equity earnings due to acquisitions of $63 million and a $73 million gain from the sale of a generating plant (see Note 1). Other Expenses increased by $110 million or 143%in 2001 due to costs to exit air transportation, fiber optic and Datapult businesses (see Note 1).Income Taxes The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book income offset by the tax effects of the sale of foreign operations. | |||
Although pre-tax book income increased considerably in 2001, Income Taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000.Extraordinary Losses and Cumulative Effect The loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change on January 1, 2002.In 2001 we recorded an extraordinary loss of$48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. | |||
The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after-tax extraordinary loss of $35 million.New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark-to-market certain fuel supply contracts that qualify as financial derivatives. | |||
The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a Cumulative Effect of Accounting Change.Other Income increased by $110 million or 33% in 2002 due to the sale of AEP S retail electric providers in Texas and due to non-operational revenue (see Note 1). Other Expenses increased | |||
$134 million or 72% in 2002 due to non-operational expenses (see Note 1).Other Income increased | |||
$240 million in 2001.A-7 mI Discontinued Operations The operations shown below were discontinued or held for sale in 2002 (See Note 12). Results of operations including impairment losses, net of tax, of these businesses have been reclassified: | |||
Company 2002 2001 2000 (in millions)SEEBOARD 5 96 S 88 5 99 CitiPower (123) (6) 17 Pushan (7) 4 7 Eastex (156) -(1)90) 5 86 S12 Reclassification Balance sheet amounts have been restated to reflect our change in accounting policy regarding certain assets and liabilities related to forward physical and financial transactions (see "Reclassification discussion Note 1.)Based upon AEP s legal rights of offset, physical and financial contracts were netted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not netted in 1998 amounts as the impact is not material.A-8 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Operations (in millions -except per share amounts)Year Ended December 31.2002 2001 2000 REVENUES: wholesale Electricity S 8,366 S 6,976 $ 7,392 wholesale Gas 2,622 2,321 442 Domestic Electricity Delivery 3,551 3,356 3,174 other Investment 16 114 105 TOTAL REVENUES 14,555 12.767 11.113 EXPENSES: Fuel and Purchased Energy: Electricity 3,154 2,195 3,470 Gas 3.153 2,749 410 TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880 Maintenance and other operation 4,013 3,710 3,482 Non-recoverable Merger Costs 10 21 203 Asset Impairments 867 --Depreciation and Amortization 1,377 1,243 1,091 Taxes other Than Income Taxes 718 667 683 TOTAL EXPENSES 13.292 10,585 9,339 OPERATING INCOME 1,263 2,182 1,774 OTHER INCOME 445 335 95 LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 --LESS: OTHER EXPENSES 321 187 77 LESS: INTEREST 785 844 999 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 11 10 11 MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -INCOME BEFORE INCOME TAXES 235 1,463 782 INCOME TAXES 214 546 602 INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT 21 917 180 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122 EXTRAORDINARY LOSSES (NET OF TAX): DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION | |||
-(48) (35)LOSS ON REACQUIRED DEBT -(2) -CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -NET INCOME (LOSS) S 51) $ 971 $ 267 AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322 EARNINGS-(LOSS) | |||
PER SHARE: Income Before Discontinued operations, Extraordinary Items and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56 Discontinued Operations (0.57) 0.26 0.38 Extraordinary Losses -(0.16) (0.11)Cumulative Effect of Accounting change (1.06) 0.06 Earnings (Loss) Per share (Basic and Diluted) I$(1.5) L3.01 $ 0.83 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 J24 See Notes to Consolidated Financial Statements beginning on page L-1.A-9 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (in millions -except share data)December 31.2002 2001 ASSETS CURRENT ASSETS: Cash and cash Equivalents | |||
$ 1,213 $ 224 Accounts Receivable: | |||
customers 466 343 Miscellaneous 1,394 1,365 Allowance for uncollectible Accounts C119) (69)Fuel, Materials and Supplies 1,166 1,037 Energy Trading and Derivative Contracts 1,046 2,125 other 935 639 TOTAL CURRENT ASSETS 6,101 5,664 PROPERTY, PLANT AND EQUIPMENT: | |||
Electric: Production 17,031 17,054 Transmission 5,882 5,764 Distribution 9,573 9,309 Other (including gas and coal mining assets and nuclear fuel) 3,965 4,272 Construction work in Progress 1,406 1,015 Total Property, Plant and Equipment 37,857 37,414 Accumulated Depreciation and Amortization 16,173 15,310 NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104 REGULATORY ASSETS 2,688 3,162 SECURITIZED TRANSITION ASSETS 735 -INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633 ASSETS HELD FOR SALE 247 721 ASSETS OF DISCONTINUED OPERATIONS | |||
-3,954 GOODWILL 396 392 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795 OTHER ASSETS 1.783 1,872 TOTAL ASSETS $34,741 See Notes to Consolidated Financia1 Statements beginning on page L-1.A-10 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31, 2002 2001 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: | |||
Accounts Payable $ 2,042 S 1,914 short-term Debt 3,164 4,011 Long-term Debt Due within one Year* 1,633 1,095 Energy Trading and Derivative Contracts 1,147 1,877 other 1.804 1.924 TOTAL CURRENT LIABILITIES 9.790 10,821 LONG-TERM DEBT* 8.487V 8.410 EQUITY UNIT SENIOR NOTES 376 -LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603 DEFERRED INCOME TAXES 3.916 4.500 DEFERRED INVESTMENT TAX CREDITS 455 491 DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819 DEFERRED GAIN ON SALE AND LEASEBACK | |||
-ROCKPORT PLANT UNIT 2 185 194 OTHER NONCURRENT LIABILITIES 1.903 1.334 LIABILITIES HELD FOR SALE 91 87 LIABILITIES OF DISCONTINUED OPERATIONS | |||
-2.582 COMMITMENTS AND CONTINGENCIES (Note 9)CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH 321 321 SUBSIDIARIES MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* | |||
145 156 COMMON SHAREHOLDERS' EQUITY: Common Stock-Par value $6.50: 2002 2001 shares Authorized. | |||
.600,000,000 600,000,000 shares Issued. ...347,835,212 331,234,997 (8,999,992 shares were held in treasury at December 31, 2002 and 2001) 2,261 2,153 Paid-in Capital 3,413 2,906 Accumulated other Comprehensive Income (Loss) (609) (126)Retained Earnings 1,999 3,296 TOTAL COMMON SHAREHOLDERS' EQUITY 7.064 8,229 TOTAL LIABILITIES AND SHAREHOLDERS EQUITY $ $39297*See Accompanying schedules. | |||
See Notes to Consolidated Financial Statements beginning on page L-1.A-11 I AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated statements of cash Flows (in millions)Year Ended December 31.2002 2001 2000 OPERATING ACTIVITIES: | |||
Net Income (Loss) $ (519) S 971 $ 267 Plus: Discontinued operations 540 (86) (122)Net income from Continuing operations 21 885 145 Adjustments for Noncash Items: Asset Impairments, Investment value and other Impairments 1,188 --Depreciation and Amortization 1,403 1,277 1,152 Deferred Investment Tax Credits (31) (29) (36)Deferred Income Taxes (66) 157 (190)Amortization of operating Expenses and Carrying charges 40 40 48 cumulative Effect of Accounting Change (18) -Equity Earnings of Yorkshire Electricity Group plc -(44)Extraordinary Loss 50 35 Deferred costs under Fuel clause Mechanisms (31) 340 (449)Mark-to-Market of Energy Trading Contracts 263 (257) (170)Miscellaneous Accrued Expenses 30 (384) 217 changes in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net) (152) 1,766 (1,530)Fuel, Materials and Supplies (127) (78) 149 Accrued Revenues (283) 35 (71)Accounts Payable 52 (478) 1,292 Taxes Accrued (216) (147) 171 Payment of Disputed Tax and Interest Related to COLI --319 change in other Assets (177) (239) (283)change in other Liabilities (237) (161) 386 Net cash Flows From Operating Activities 1,677 2,759 1.141 INVESTING ACTIVITIES: | |||
Construction Expenditures (1,722) (1,654) (1,468)Purchase of Gas Pipe Line -(727) -Purchase of U.K. Generation | |||
-(943) -Purchase of coal Company -(101) -Purchase of Barging Operations | |||
-(266) -Purchase of wind Generation | |||
-(175) -Proceeds from Sale of Retail Electric Providers 146 --Proceeds from sale of Foreign Investments 1,117 383 -Proceeds from Sale of U.S. Generation | |||
-265 -other 37 (42) (18)Net Cash FlowS used For Investing Activities (422) (3.260) (1.486)FINANCING ACTIVITIES: | |||
Issuance of Common stock 656 11 14 Issuance of Minority Interest -744 -Issuance of Long-term Debt 2,893 2,863 878 Issuance of Equity unit Senior Notes 334 -Retirement of Cumulative Preferred stock (10) (5) (21)Retirement of Long-term Debt (2,514) (1,570) (1,303)change in short-term Debt (net) (829) (790) 1,328 Dividends Paid on Common stock (793) (773) (805)Dividends on Minority Interest in subsidiary | |||
-(5) -Net Cash Flows From (used for) Financing Activities (263) 475 91 Effect of Exchange Rate Changes on Cash (3) (1) 30 Net Increase (Decrease) in cash and cash Equivalents 989 (27) (224)cash and cash Equivalents from Continuing operations Beginning of Period 224 251 475 Cash and cash Equivalents from Continuing Operations | |||
-End of Period $L213 L 224 S 251.Net Increase (Decrease) in Cash and cash Equivalents from Discontinued operations | |||
$ (100) $ 17 $ (17)Cash and cash Equivalents from Discontinued operations Beginning of Period 108 91 108 Cash and Cash Equivalents from Discontinued operations End of Period $ 8A08 $ 91 See Notes to consolidated Financial Statements beginning on page L-1.A-12 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equitv and Comprehensive Income (in millions)DECEMBER 31, 1999 Issuances cash Dividends Declared Other comprehensive Income: Other Comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment Reclassification Adjustment For LOSS Included in Net Income Net Income Total Comprehensive Income DECEMBER 31, 2000 Issuances cash Dividends Declared other comprehensive Income: Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability Net Income Total Comprehensive Income DECEMBER 31, 2001 Issuances cash Dividends Declared Other Com prehensive Income: Other comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability unrealized Loss on securities Available For Sale Net Income (Loss)Total comprehensive Income DECEMBER 31, 2002 Common stock shares Amount 331 $2,149-3 331 331 17$2, 152 1$2,153 108 Paid-In Capi tal$2,898 11 6 S2,915 9 (18)S2,906 568 (61)S 3.13 Retained Earnings S3,630 (805)(2)267$3,090 (773)8 971$3,296 (793)15 (519)1S9M Accumulated other comprehensive Income (Loss)$ (4)(119)20 S (103)(14)(3)(6)S (126)117 (13)(585)(2)sff)Total$8,673 14 (805)4 7,886 (119)20 267 168$8,054 10 (773)(10)7,281 (14)(3)(6)971 948$8,229 676 (793)(4 )(163)117 (13)(585)(2)(519)(1.002)MA See Notes to Consolidated Financial statements beginning on page L-1.A-13 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31. 2002 Call Price per Shares Shares Amount (In share(a) Authorized(b) | |||
Outstandinatf) | |||
Millions)Not subject to Mandatory Redemption: | |||
4.00% -5.00% S102-$110 1,525,903 608,150 $ 61 Subject to Mandatory Redemption: | |||
5.90% -5.92% (c) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 51 Total subject to Mandatory Redemption (c) 84 Total Preferred stock 1145 December 31. 2001 Call Price per Shares shares Amount (In share(a) Authorized(b) | |||
Outstandino(f) | |||
Millions)Not subject to Mandatory Redemption: | |||
4.00% -5.00% S102-S110 1,525,903 614,608 $ 61 subject to Mandatory Redemption: | |||
5.90% -5.92% Cc) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 100,000 10 Total subject to Mandatory Redemption (c) 95 Total Preferred Stock S156 NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. | |||
The involuntary liquidation preference is S100 per share for all outstanding shares.(b) AS of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and 7,713,501 shares of $100,$25 and no par value preferred stock, respectively, that were authorized but unissued.(c) shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements. | |||
The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.(d) Not callable prior to 2003, after that the call price is $100 per share plus accrued dividends.(e) with sinking fund.(f) The number of shares of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares in 2001 and 209,563 shares in 2000.A-14 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries Maturity weighted Average Interest Rate December 31. 2002 Interest Rates 2002 at December 31.2001 December 31.2002 2001 (in millions)FIRST MORTGAGE BONDS (a)2002 -2004 2005 -2008 2022-2025 INSTALLMENT PURCHASE CONTRACTS (b)2002-2009 2011-2030 NOTES PAYABLE (c)2002-2021 SENIOR UNSECURED NOTES 2002 -2005 2006-2012 2032-2038 JUNIOR DEBENTURES 2025-2038 SECURITIZATION BONDS 2003-2016 OTHER LONG-TERM DEBT (d)Unamortized Discount (net)Total Long-term Debt outstanding Less Portion Due Within One Year Long-term Portion EQUITY UNIT SENIOR NOTES 2007 6.87%6.90%7.66%4.62%5.83%5.54%5.53%5.91%6.64%7.90%5.40%5.75%6.00%-7.85% | |||
6.20%-8%6.875%-8.7% | |||
3.75%-7.70% | |||
1.35%-8.20% | |||
3.732%-9.60% | |||
2.12%-7.45% | |||
4.31%-6.91% | |||
6.00%-7-3/8% | |||
7.60%-8.72% | |||
6.00%-7.85% | |||
6.20%-8%6-7/8%-8.80% | |||
1.80%-7.70% | |||
1.55%-8.20% | |||
4.048%-9.60% | |||
2.31%-7.45% | |||
6.125%-6.91% | |||
7.20%-7-3/8% | |||
7.60%-8.72% | |||
$ 648 463 773 396 1,284 520 1,834 2,295 690 205 797 247 (32)10.120 1 633 S 1,246 699 850 446 1,234 217 1,910 1,727 340 618 258 (40)9, 505 1.095 L 8410 3.54%-6.25% | |||
5.75%S-376 NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.(b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. | |||
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. | |||
At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. | |||
variable rates generally relate to specified short-term interest rates.(d) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 9 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. | |||
Long-term debt outstanding at December 31, 2002 (includes Equity Unit senior Notes) is payable as follows: (in millions)2003 2004 2005 2006 2007 Later Years Unamortized Discount Total S 1,633 824 993 1, 611 1,081 4.386 10,528 32£10,9 A-15 AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Combined Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Goodwill and other Intangible Assets Merger Nuclear Plant Restart Rate Matters Effects of Regulation customer Choice and Industry Restructuring Commitments and contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans stock-Based compensation Business Segments Risk Management, Financial Instruments And Derivatives Income Taxes Basic and Diluted Earnings Per share Supplementary Information Power and Distribution Projects Leases Lines of credit and sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Minority Interest in Finance subsidiary Equity units Subsequent Events (unaudited) combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 5 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 15 Note 16 Note 17 Note 18 Note 19 Note 20 Note 21 Note 22 Note 23 Note 24 Note 25 Note 26 Note 27 Note 30 A-16 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Companys management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted ouraudits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 3 to the consolidated financial statements, the Company adopted SFAS 142, 'Goodwill and Other Intangible Assets, effective January 1, 2002.As discussed in Note 13 to the consolidated financial statements, the Company recorded certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002./s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 A-17 L_MANAGEMENTS RESPONSIBILITY The management of American Electric Power Company, Inc. has prepared the financial statements and schedules herein and is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. | |||
These statements have been prepared in conformity with accounting principles generally accepted in the United States of America, using informed estimates where appropriate, to reflect the Company s financial condition and results of operations. | |||
The information in other sections of the annual report is consistent with these statements. | |||
The Company s Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Companys established internal control structure over financial reporting. | |||
The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP -independent auditors and the Companys internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. | |||
The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the previous page.The auditors provide an objective, independent review as to management s discharge of its responsibilities insofar as they relate to the fairness of the Company s reported financial condition and results of operations. | |||
Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Companys internal control structure over financial reporting. | |||
A-18 AEP GENERATING COMPANY AEP GENERATING COMPANY Selected Financial Data INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant Year Ended December 31.2002 2001 2000 1999 1998 (in thousands) | |||
$213,281 $227,548 $228,516 $217,189 $224,146 207,152 220.571 220,092 211,849 215,415 6,129 6,977 8,424 5,340 8,731 3,681 3,484 3,429 3,659 3,364 2,258 2,586 3.869 2.804 3.149 ,$L52 $ 77875 $ ,94 $6J195 $ Ai December 31.2002 2001 2000 1999 1998 (in thousands) | |||
$652,213 358.174$648,254 337,151$-3-1-,10$642,302 315.566$36,736$640,093 295.065 ,$345,028$636,460 277. 855 Total Assets$349,729 $361,41 $374,602 A U $403 892 Common stock and Paid-in capital Retained Earnings Total Common shareholder's Equity$ 24,434 18.163$ 4259$ 24,434 13.76$ 3-8,19-5$ 24,434 9,722$ 30,235 3.673$ 36,235 2,770$ 900 Long-term Debt (a)Total Capitalization And Liabilities S_4i8QZ $4,793 $ 44,808 $ 48 44,79 UAJTZ9 $36 1 ,41 $374,602 $98 4 $403 1892 (a) Inc7uding portion due within one year.B-1 AEP GENERATING COMPANY Management s Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. | |||
Operating Expenses Decrease Operating Expenses decreased 6% as follows: Operating Revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved long-term unit power agreements. | |||
Under the terms of its unit power agreement, l&M will purchase all of AEGCo's Rockport capacity unless it is sold to other utilities. | |||
A unit power agreement between AEGCo and KPCo expires in 2004.The KPCo unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. | |||
The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. | |||
Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. | |||
In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. | |||
Results of Operations (dollars in thousands) | |||
._ _ .._ ._ .., _ _ _ _ _ _ _ _ _Increase (Decrease) | |||
From Previous Year Amount %$(13,723) | |||
(13)1,899 17 565 6 137 1 Fuel other operation Maintenance Depreciation Taxes other Than Taxes Income Taxes Total Income (976)(1.321)S (3,41)(23)(46)(6)The decrease in Fuel expense reflects a decrease in generation and lower average fuel costs.Other Operation expense increased due to increased costs for employee benefits and property insurance. | |||
The increase in Maintenance expense can be attributed to shorter duration of maintenance outages for boiler inspection and repair in 2001.Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and personal property taxes reflecting a favorable change in the law which lowered the tax for Rockport Plant.Net Income decreased | |||
$323,000 or 4% as a result of limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant.The decrease in Income Taxes attributable to operations is primarily due to a decrease in pre-tax operating income and a change in estimate for state income tax accruals.Operating Revenues Decrease The decrease in Operating Revenues of$14,267,000 or 6% reflects a decrease in recoverable expenses, primarily fuel.B-2 AEP GENERATING COMPANY Statements of Income OPERATING REVENUES OPERATING EXPENSES: Fuel Rent -Rockport Plant Unit 2 other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Year Ended December 31.2002 2001 2000 (in thousands) | |||
$213.281 $227.548 $228,516 TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDITS INTEREST CHARGES NET INCOME 89,105 68,283 12,924 9,418 22,560 3,281 1.581 207,152 6,129 343 198 3,536 2.258.$ -752 102,828 68,283 11,025 8,853 22,423 4,257 2.902 220. 571 6,977 30 16 3,470 2.586$_zl875 102,978 68,283 10,295 9,616 22,162 3,854 2.904 220.092 8,424 6 17 3,440 3.869$ 7L984 Statements of Retained Earnings RETAINED EARNINGS JANUARY 1 NET INCOME CASH DIVIDENDS DECLARED RETAINED EARNINGS DECEMBER 31 See Notes to Financia7 Statements beginning on page L-1.Year Ended December 31.2002 2001 2000 (in thousands) | |||
$13,761 $ 9,722 $3,673 7,552 7,875 7,984 3 150 3.836 1.935 18&-63 $13 ,761 $4X7 B-3 AEP GENERATING COMPANY Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production | |||
$637,095 $638,297 General 4,728 3,012 Construction work in Progress 10.390 6.945 Total Electric Utility Plant 652,213 648,254 Accumulated Depreciation 358,174 337.151 NET ELECTRIC UTILITY PLANT 294,039 311.103 OTHER PROPERTY AND INVESTMENTS 119 119 CURRENT ASSETS: cash and cash Equivalents | |||
-983 Accounts Receivable: | |||
Affiliated Companies 18,454 22,344 Miscellaneous | |||
-147 Fuel 20,260 15,243 Materials and supplies 4,913 4,480 Prepayments | |||
-244 TOTAL CURRENT ASSETS 43.627 43.441 REGULATORY ASSETS 4.970 5.207 DEFERRED CHARGES 6,974 1.471 TOTAL ASSETS S3A 4 29 $6134 see Notes to Financial Statements beginning on page L-1.B4 AEP GENERATING COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common stock Par value $1,000: Authorized and outstanding 1,000 Shares $ 1,000 $ 1,000 Paid-in capital 23,434 23,434 Retained Earnings 18163 13761 Total Common shareholder s Equity 42,597 38,195 Long-term Debt 44.802 44,793 TOTAL CAPITALIZATION 87.399 82.988 OTHER NONCURRENT LIABILITIES 301 76 CURRENT LIABILITIES: | |||
Advances from Affiliates 28,034 32,049 Accounts Payable: General 26 7,582 Affiliated Companies 15,907 1,654 Taxes Accrued 2,327 4,777 Rent Accrued Rockport Plant Unit 2 4,963 4,963 other 1.111 3.48 TOTAL CURRENT LIABILITIES 52.368 54.506 DEFERRED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 111,046 116.617 REGULATORY LIABILITIES: | |||
Deferred Investment Tax credits 52,943 56,304 Amounts Due to Customers for Income Taxes 16.670 22.725 TOTAL REGULATORY LIABILITIES 69.613 79.029 DEFERRED INCOME TAXES 29.002 27,975 DEFERRED CREDITS -150 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES | |||
$349,729 $M1,341I See Notes to Financia7 statements beginning on page L-1.B-5 AEP GENERATING COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation Deferred Income Taxes Deferred Investment Tax Credits Amortization of Deferred Gain on sale and Leaseback | |||
-Rockport Plant Unit 2 Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable Fuel, Materials and supplies Accounts Payable Taxes Accrued other Assets other Liabilities Net Cash Flows From operating Activities | |||
$ 7,552 S 7,875 $ 7,984 22,560 (5,028)(3,361)(5,571)4,037 (5,450)6,697 (2,450)(5,211)(2.295)11,480 22,423 (6,224)(3,414)(5,571)1,224 (4,738)(4, 597)(216)(569)(1.244)4,949 22,162 (5,842)(3,396)(5,571)1,392 6,486 (13,157)708 1,636 (404)11. 998 INVESTING ACTIVITIES Construction Expenditures FINANCING ACTIVITIES: | |||
Return of Capital to Parent Company change in short-term Debt (net)Change in Advances From Affiliates (net)Dividends Paid Net Cash Flows From (Used For)Financing Activities (5,298)(4,01-5)(3,150)(7.165)(6,868)3,981 (3.836)145 (5,190)(5,801)(24,700)28,068 (1.935)(4,368)Net Increase (Decrease) in cash and cash Equivalents Cash and cash Equivalents January 1 cash and cash Equivalents December 31 supplemental Disclosure: | |||
Cash Paid for interest net of capitalized amounts was and for income taxes was $7,884,000, $8,597,000 and respectively. | |||
(983)983$~ _(1,774)2,757$ 98 2,440 317$2,019,000, $1,509,000 and $3,531,000 | |||
$6,820,000 in 2002, 2001 and 2000, See Notes to Financial Statements beginning on page L-1.B-6 11, AEP GENERATING COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) | |||
COMMON STOCK EQUITY (a) $42.597 $38.195 LONG-TERM DEBT Installment Purchase Contracts City of Rockport (b)series Due Date 1995 A, 2025 (c) 22,500 22,500 1995 B, 2025 (c) 22,500 22,500 unamortized Discount (198) (207)TOTAL LONG-TERM DEBT 44.802 44,793 TOTAL CAPITALIZATION | |||
$87399 29 (a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There were no other material transactions affecting Common stock and Paid-in Capital in 2002, 2001 and 2000.(b) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant.(C) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006.See Notes to Financia 7 Statements beginning on page L-1.B-7 AEP GENERATING COMPANY Index to Combined Notes to Financial Statements The notes to AEGCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to AEGCo. The combined footnotes begin on page L-1.significant Accounting Policies Effects of Regulation Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 7 Note 9 Note 10 Note 11 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 B-8 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of AEP Generating Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 B-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES | |||
=AEP TEXAS CENTRAL COMPANY AND Selected Consolidated Financial Data SUBSIDIARIES 2002 Year Ended December 31.2001 2000 (in thousands) 1999 INCOME STATEMENTS DATA: operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements Gain (Loss) on Reacquired Preferred Stock$1,690,493 1.296.760 393,733 8,079 125.871 275,941 275,941$1,738,837 1,443.106 295,731 5,324 116.268 184,787 (2.509)182,278$1,770,402 1.463.304 307,098 7,235 124,766 189,567 189,567$1,482,475 1.188.490 293,985 8,113 114 380 187,718 (5 517)182,201 6,931 1998$1,406,117 1 123.330 282, 787 760 122.036 161,511 161,511 6,901 241 242 241 4 (2.763)Earnings Applicable To Common stock$_275704 1$_182L 06$ 172.507 L$_ 15-461Q Year Ended December 31.2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation And Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$5,625,736 2.405.492$320 -244$5'536P438 | |||
$ 187,898 (73,160)986.396$1- 1O1t 13A$ 5,942-2001$5,769,707 2.446.027$ 573,903 826,197$1,420QlQQ 2000 (in thousands) | |||
$5,592,444 2.297,189$ 573,904 792,219$ 5,951 1999$5,511,894 2.247,225$ 573,904 758.894-$-I 33-,79$5.95 1998$5,336,191 2.072.686$4,735,_ff | |||
$ 573,904 734. 387$1 1QWLZX CPL Obli ated, Mandatori 1y Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior subordinated Debentures of CPL Long-term Debt (a)Total capitalization And Liabilities | |||
$-13-6 Z 5-SI136 25Q$148,500$1,454,559 | |||
$154,5I41$5,467,01$4,735,656 (a) Including portion due within one year.C-1 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Managrement s Discussion and Analvsis of Results of Operations AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TCC s behalf byAEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TCC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TCC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TCC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. | |||
As a result of the formation of the affiliated REP, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. | |||
The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC s sales as described below under"Results of Operations. | |||
In December 2002, AEP sold the affiliated REP to an unrelated third party who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Affiliates. | |||
Subsequent to the sale, transactions with the REP were classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income increased | |||
$94 million or 51 % primarily due to $262 million of revenues associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas which resulted in the loss of customers and reduced prices (see Note 8).In 2001, Income Before Extraordinary Item decreased | |||
$5 million or 3%, primarily resulting from a settlement of Texas municipal franchise fees and increased Maintenance expenses.Changes in Operating Revenues Increase (Decrease) | |||
From Previ ous Year (dollars in millions)2002 2001 Amount % Amount whol esal e El ectri ci ty*Energy Delivery*Sales to AEP S (1, 096.4) (90) S(29.9) (2)81.4 17 (5.6) (1)Affiliates 966.7 N.M. 4.0 11 Total 5(8.) (3) 5 31. 5) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful In 2002, Wholesale Electricity revenues decreased as a result of the elimination of TCCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins offset in part by the interchange cost reconstruction C-2 (ICR) adjustments (see Note 6). In 2001, the decrease in Wholesale Electricity revenues was primarily attributable to unfavorable wholesale power marketing and trading conditions. | |||
In 2002, Sales to AEP Affiliates revenue increased primarily due to increased revenues from the newly created affiliated REP.Although TCC sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue. Revenues for 2002 included $262 million of revenues, associated with recognition of stranded costs in Texas (see Note 8). Energy Delivery revenue also included revenues received for securitized assets beginning in 2002 (see Note 8).Chances in Operatinc ExDenses based on the current spot market price.Changes in natural gas prices affect TCC s fuel expense; however, they generally did not impact results of operations in 2001 and 2000 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.In 2002, the increase in Wholesale Electricity Purchased Power expense is due to higher MWH purchases from the market where we could purchase power at prices lowerthan our cost to produce. ICR adjustments also had the effect of increasing Wholesale Electricity Purchased Power expense and decreasing AEP Affiliates Purchased Power expense in 2002 (see Note 6).In 2001, Purchased Power increased overall largely due to higher natural gas prices.Although gas prices declined in 2001, they were higher during the first half of 2001 when TCC was making most of its purchases. | |||
In 2002, Other Operation expense decreased due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses.Increase (Decrease) | |||
From Previous Year A Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreci ati on And Amortization Taxes other Than Income Taxes Income Taxes Total V((dollars in millions) | |||
In 2002, Maintenance expense decreased 2002 2001 due to two scheduled | |||
'18 month interval mount % Amount % refueling outages for STP during 2001 that increased Maintenance expense above the:246.2) (50) SC58.8) C11) 2002 and 2000 levels. Also contributing to the decrease in 2002, and the increase in 83.5 65 C16.2) (11) 2001, was an increase in Maintenance 83.5* 65 (16.2) (l ) expense for scheduled major overhauls of (35.3) (60) 26.0 80 four power plants in 2001.(17.1) (5) 1.7 1-7 1 -I -tO'.i.) L.+/-+/-J +/-U. I IO In 2002, the increase in Depreciation and Amortization is attributable to the amortization 45.8 27 (10.4) (6) of regulatory assets that were securitized in 4. 6 5 14.4 19 the first quarter of 2002, offset by the 26.1 23 12.4 12 elimination of excess earnings expense in.46) (10) -A) C') 2002 under Texas Restructuring Legislation (see Note 8).la In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of fuel and decreased generation. | |||
The decrease in Fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. TCC used natural gas as fuel for 32% of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax, due to deregulation. | |||
In 2001, Taxes Other Than Income Taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees, and a new tax levied by the C-3 PUCT, the Texas System Benefit Fund Assessment. | |||
In 2002, the increase in Income Taxes is due to an increase in pre-tax income offset by changes in timing between book/tax accounting differences in state income taxes.In 2001 the increase in Income Tax expense is primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income.Other Changes In 2002, Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the energy related construction projects included in Nonoperating Income increased | |||
$34 million and $15 million in 2002 and 2001. The expenses associated with these projects included in Nonoperating Expenses increased$32 million and $14 million in 2002 and 2001.current cost to generate electricity, TCC proposed in September 2002 to "inactivate various, high-cost gas fired generating facilities. | |||
In the third quarter 2002, TCC recorded an impairment charge of approximately | |||
$95.6 million (pre-tax) related to these plants and recorded approximately | |||
$4.0 million (pre-tax) for severance charges.Both of these charges were deferred and recorded in RegulatoryAssets Designated for or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 8). In the fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional plant impairments, fuel inventory and materials and supplies, and an additional | |||
$1.5 million pre-tax charge was recorded related to severance charges (see Note 13) related to the Inactivated plants. The entire $23.1 million was also deferred and recorded in Regulatory Assets Designated for or Subject to Securitization. | |||
In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax non-operating income.In 2002, Interest Charges increased primarily due to higher levels of outstanding debt (see TCC s schedule of Long-term Debt and Consolidated Statements of Capitalization for further information). | |||
In 2001, the decrease in interest charges was attributable to lower average interest rates associated with short-term and long-term debt.Extraordinary Loss The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas.Impairment As a result of TCC s recent abilityto purchase electricity at a significantly lower price than its C-4 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP A ffiliates TOTAL OPERATING REVENUES$ 127,502 554,547 1.008.444 1.690.493 OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES 245,834 211,358 23,406 304,094 63,392 214,162 95,500 139.014 1. 296, 760$1,223,893 473,182 41.762 1. 738. 837 492,057 127,816 58,641 321,227 71,212 168,341 90,916 112.896 1.443.106$1,253,836 478,814 37.752 1.770.402 550,903 144,021 32,591 319,539 60,528 178,786 76,477 100.459 1.463. 304 OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)393,733 53,141 41,910 3,152 295,731 22,552 17,626 (398)307,098 5,830 3,668 (5,073)INTEREST CHARGES 125. 871 116.268 124,766 INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567 EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001)NET INCOME 275,941 (2.509)182,278 242 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS GAIN ON REACQUIRED PREFERRED STOCK 241 241 4 EARNINGS APPLICABLE TO COMMON STOCK$ -18Z-16 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 (in thousands) | |||
$182,278 2000$189,567 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME$275,941 (36)(73,124)$18 2- dl1 S1W2,WA The common stock of TCC is owned by a wholly owned subsidiary of AEP.See Notes to Financia7 statements beginning on page L-1.C-5 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31.2002 2001 2000 (in thousands) | |||
BEGINNING OF PERIOD $826,197 $792,219 $758,894 NET INCOME 275,941 182,278 189,567 DEDUCTIONS (ADDITIONS): | |||
Capital stock Gains (4) --Cash Dividends Declared: Common stock 115,505 148,057 156,000 Preferred stock 241 242 241 other -1 1 BALANCE AT END OF PERIOD 26 $ 6197 $792,219 The common stock of TCc is owned by a wholly owned subsidiary of AEP.see Notes to Financial statements beginning on page L-1.C-6 | |||
--AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Nuclear Fuel Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS SECURITIZED TRANSITION ASSETS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
General Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued Utility Revenues Energy Trading and Derivative Contracts Prepayments and other current Assets TOTAL CURRENT ASSETS REGULATORY ASSETS REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION NUCLEAR DECOMMISSIONING TRUST FUND DEFERRED CHARGES TOTAL ASSETS See Notes to Financial Statements beginning on page L-1.$2,903,942 698,964 1,296,731 258,386 200,947 266.766 5,625,736 2.405.492 3.220.244 3.977 734. 591 4.392 85,420 113,543 121,324 (346)32,563 51,593 27,150 22,493 2.133 455.873 458. 552 336.444 98.474 43,891 Sig56 E438$3,169,421 663,655 1,279,037 241,137 169,075 5,769,707 2.446,027 3. 323.680 47,950 28 039 10,909 38,459 6,249 (186)38,690 55,475 34,480 2.742 186 818 226. 812 959,294 98.600 21.837$4,9303 C-7 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock $25 Par Value: Authorized 12,000,000 shares outstanding 2,211,678 shares at December 31, 2002 6,755,535 shares at December 31, 2001 Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock CPL obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of CPL Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
short-term Debt Affiliates Long-term Debt Due within one Year Advances from Affiliates (net)Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$ 55,292 132,606 (73,160)986 396 1,101,134 5,942 136,250 1,209.434 2.452.760 74.572 650,000 229,131 126,711 72,199 36,242 666 24,791 51,205 19,811 36. 698 1.247.454 1.261.252 117.686 1,713 201.001 S5,356 A438$ 168,888 405,015 826.197 1,400,100 5,952 136,250 988.768 2,531.070 10.905 265,000 354,277 65,307 49,301 26,744 83,512 23,715 40,987 18,076 926.919 1,163.795 122.892 17,675 119.774$4 1 9,83A3D C-8 | |||
--l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income Adjustments to Reconcile Net Income to Net cash Flows from Operating Activities: | |||
Depreciation and Amortization Extraordinary Loss on Reacquired Debt Deferred Income Taxes Deferred Investment Tax credits Mark-toMarket Energy Trading and Derivative Contracts change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Interest Accrued Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission coordination Agreement settlement Texas wholesale Clawback (see Note 7)change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From Sales of Property and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt change in short-term Debt Affiliate (Net)Retirement of Common stock Retirement of Preferred stock Retirement of Long-term Debt change in Advances from Affiliates (net)special Deposit for Reacquisition of Long-term Debt Dividends Paid on Common stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities | |||
$275,941 $182,278 $189,567 214,162 113,655 (5,206)(1,558)(189,999)(4,899)27,490 (27,150)(6,167)(58,721)16,455 (262,000)(534)56.024 147.493 (151,645)143 (151. 502)797,335 650,000 (386,005)(6)(639,492)(227,566)(115, 505)(241)78.520 168,341 2,509 (72,568)(5,208)(12,048)52,862 (18,215)(2,502)(55, 311)27,986 179,866 10,767 11,163 469,920 (193,732)(354)(194.086)260,162 (475,606)84,565 (148,057)(242)(279,178)178,786 16,263 (5,207)8,191 (32,902)8,680 11,494 45,873 14,405 (96,872)15,519 589 12 .243 366,629 (199,484)(199.484)149,248 (151,440)(52,446)50,000 (156,000)(249)(160.887)Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1 Cash and cash Equivalents December 31 74,511 10.8909 (3,344)14.253 SLQ 3Q9 6,258 7.995 illw53 supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and for income taxes. was$95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and 2000,respectively. | |||
see Notes to Financial statements beginning on page L-1.C-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
S1.10o.134 S1.400.100 COMMON SHAREHOLDER S EQUITY (a)PREFERRED STOCK 3,035,000 authorized shares, 5100 par value Not Subject to Mandatory Redemption: | |||
call Price -December 31, Number of shares Redeemed series 2002 Year Ended December 31. Dec 2002 2001 2000 Shares outstanding | |||
:ember 31. 2002 4.00% S105.75 100 --41,938 4,194 4.20% 103.75 ---17,476 1.748 Total Preferred stock 5.942 TRUST PREFERRED SECURITIES: | |||
TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of TCC, 8.00%due April 30, 2037 136.250 LONG-TERM (See schedule of Long-term Debt): First Mortgage Bonds 152,353 Securitization Bonds (a) 796,635 Installment Purchase Contracts 489, 577 Senior unsecured Notes -Less Portion Due within One year (229.131)Long-term Debt Excluding Portion Due within one Year 1.209.434 TOTAL CAPITALIZATION (a) In February 2002, TCC issued securitization bonds. S386 million of the proceeds 4,543,857 shares of common stock.See Notes to Financial Statements beginning on page L-1.4,204 1,748 5.952 136. 2 50 614,200 489,568 150,000 (265.000)988. 768 was used to retire C-1 0 i -AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
December 31, 2002 2001 (in thousands) | |||
% Rate Due 7.25 2004 7.50 2002 6-7/8 2003 7-1/8 2008 7.50 2023 6-5/8 2005 Total October 1 December 1 February 1 February 1 April 1 July 1 S 27,400 16,418 18,581 17,996 71. 958$100,000 115,000 49,200 75,000 75,000 200 000 ikQu Q% Rate Due Matagorda County Navigation District, Texas: 6.00 2028 July 1 6-1/8 2030 May 1 3.75 2030(a) May 1 4.00 2030(a) May 1 4.55 2029(a) Nov .Guadalupe-Blanco River Authority District, Texas: (b) 2015 November 1 Red River Authority District, Texas:$120,265 60,000 111,700 50,000 100,635 S120,265 60,000 111,700 50,000 100,635 First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Securitization Bonds outstanding were as follows: 40,890 40,890 Final Payment Maturity Rate Date Date 3.54 1/15/2005 1/15/2007 5.01 1/15/2008 1/15/2010 5.56 1/15/2010 1/15/2012 5.96 7/15/2013 7/15/2015 6.25 1/15/2016 1/15/2017 unamortized Discount Total December 31.2002 2001 (i~nthousands) 6.00 2020 June 1 6,330 6,330 unamortized Discount (243) (252)Total S4O9,577 (a)installment Purchase contract provides for bonds to be tendered in 2003 for 3.75% and 4.00% series and in 2006 for 4.55% series.Therefore, these installment purchase contracts have been classified for payments in those years.(b) A floating interest rate is determined monthly. The rate on December 31, 2002 was 1.7%.Under the terms of the installment purchase contracts, TCC is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: S128,950 154,507 107,094 214,927 191,857 (700)5796>6i5$In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 2002 February 22 Cc)Total December 31.2002 2001 (in thousands) | |||
$ -S150.000 S -$150.AlOO (c) A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.56%.C-11 At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 229,131 75,951 121,937 152,900 52,729 806.860 1,439,508 (943)51,438,56 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of TCC.C-12 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to TCC s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to TCC. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Merger Rate Matters Effects of Regulation customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Asset Impairment and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 C-1 3 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas Central Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Companyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31,2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 C-14 | |||
-J al AEP TEXAS NORTH COMPANY AEP TEXAS NORTH COMPANY Selected Financial Data 2002 Year Ended December 2001 2000 (in thousands) 31 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income (Loss) Before Extraordinary Item Extraordinary Loss Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$ 450,740 442.869 7,871 (703)20,6845 (13,677)(13,677)104$556,458 523.068 33,390 2,195 23, 275 12,310 12,310 104$571,064 518.723 52,341 (1,675)23,216 27,450 27,450 104 1999$445,709 391.910 53,799 2,488 24,420 31,867 (5.461)26,406 104 1998$424,953 365,677 59,276 2,712 24.263 37,725 37,725 104$ 37,621$ (13.781)S 34-6 S 26,302 2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric utility Plant Total Assets Common stock and Paid-in Capital Accumulated other Comprehensive Income (LosS)Retained Earnings Total Common Shareholder's Equity$1,201,747 521.792 S 679,955$ 877,175$ 139,565 (30,763)71.942$1&80,744 2001$1,260,872 546,162$ 714,710$ 139,565 105.970$_241S53-5 December 31.2000 (in thousands) | |||
$1,229,339 515,041$ 714,298 51,087. 504$ 139,565 122,588$_262 153 1999$1,182,544 495.847 5 686,697$ 861,205$ 139,565 113,242 S_252 s807 1998$1,146,582 473.503$ 673,079$,819,446 S 139,565 114.940 S 254,505 Cumulative Preferred stock: Not subject to Mandatory Redemption S 2,367 Long-term Debt (a) $ 132,50 Total Capitalization And Liabilities S 877L21Z5 S 255,967 255.7$S_22 _N S 6 8 L&6t4875 S1.087.iOA 5 8612,05 S _819A446 (a) Including portion due within one year.D-1 AEP TEXAS NORTH COMPANY Manaaement s Narrative Analysis of Results of ODerations AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TNC s behalf byAEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory. | |||
Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TNC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TNC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TNC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. | |||
As a result of the formation of the affiliated REP, effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. | |||
The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC s sales as described below under"Results of Operations. | |||
In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale, during 2002, sales to the affiliated REP were classified as Sales to AEP Affiliates. | |||
Subsequent to the sale, transactions with the REP will be classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income decreased | |||
$26.0 million or 211 % primarily due to a $38.1 million long-lived asset impairment charge ($24.8 million net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a$4.7 million impairment charge ($3.1 million net of tax) related to the abandonment of a wind-powered generation facility (see Note 13).Changes in Operatina Revenues Increase (Decrease) | |||
From Previous Year (in millions) h wholesale Electricity* | |||
Energy Delivery*sales to AEP S(231. 7)(95.7)(63)(57)Affiliates 221.7 N.M.Total ()05.7) (19)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful Wholesale Electricity revenues decreased as a result of the elimination of TNCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins, partially offset by the ICR adjustments (see Note 6).D-2 Sales to AEP Affiliates increased primarily due to increased revenues from the newly created affiliated REP. Although TNC sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue.Changes in Operating Expenses Increase (Decrease) | |||
From Previous Year (in millions) | |||
%Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total S(76.7)10.0 (19 .1)(6.3)42.9 (7.1)(5.8)(18.1)gun 2)(43)14 (34)(6)N.M.(14)(21)N.M.(15)electricity at a significantly lower price than its current cost to generate electricity, TNC proposed in September 2002 to Inactivate various, high-cost gas fired generating facilities. | |||
TNC recorded an impairment charge in the third quarter 2002 of approximately | |||
$34.2 million related to these plants, which was recorded in Asset Impairments expense. In the fourth quarter 2002, an additional asset impairments charge of $3.9 million was also recorded in connection with these plants, along with a$4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, a $1.2 million charge associated with fuel inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (recorded in Other Operations) was recorded in the fourth quarter of 2002 related to the"inactivated plants.Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation and the elimination of regulatory asset amortization that ended in 2001.The decrease in Taxes Other Than Income Taxes is primarily a result of one time 2001 assessments and a decrease in the gross receipts tax due to deregulation. | |||
The decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the impairment of various generating facilities. | |||
Other Changes Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the aforementioned energy related construction projects included in Nonoperating Income increased | |||
$45.5 million in 2002. The expenses associated with these projects included in Nonoperating Expenses increased | |||
$43.0 million in 2002.Interest Charges declined primarily due to lower interest rates.N.M. = Not Meaningful Fuel expense decreased due to a decrease in the average unit cost of fuel and decreased generation required due to decreased energy sales. TNC used natural gas as fuel for 42%of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect TNC s fuel expense;however, they generally did not impact results of operations in 2001 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.The net decline in total Purchased Power expense in 2002 was mainly due to both reduced MWHs purchased and reduced prices, partially offset by ICR adjustments (see Note 6).Other Operation expense decreased slightly in 2002 due to lower factoring and transmission expenses, offset in part by a$1.4 million write-down of material and supply inventory associated with the impaired plants.As a result of TNC s recent ability to purchase D-3 it, AEP TEXAS NORTH COMPANY Statements of Operations Year Ended December 31, 2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Tax Expense (Credit)TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDIT INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$136,962 73,353 240,425 450.740 100,466 80,391 37,582 104,960 42,898 22,295 43,620 22,471 (11.814)442.869 7,871 53,763 54,755 (289)20.845 (13,677)104 2001 (in thousands) | |||
$368,741 169,036 18.681 556.458 177,140 70,395 56,656 111,248 22,343 50,705 28,319 16.262 523.068 33,390 12,199 10,695 (691)23.275 12,310 104> t12 20l6$376,206 176,204 18,654 571,064 183,154 68,080 57,773 93,078 21,241 55,172 25,321 14,904 518.723 52,341 9,530 12,664 (1,459)23.216 27,450 104$ 27,3A6 2000 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
$(13,677) | |||
$12,310 $27,450 NET INCOME (LOSS)OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(15)-(30.74)i$12 1 3i The common stock of TNC is owned by a wholly owned subsidiary of AEP.see notes to Financial statements beginning on page L-1.D-4 AEP TEXAS NORTH COMPANY Statements of Retained Eaminqs Year Em 2002 (in BEGINNING OF PERIOD $105,970 i NET INCOME (LOSS) (13,677)DEDUCTIONS: | |||
cash Dividends Declared: Common Stock 20,247 Preferred stock 104 BALANCE AT END OF PERIOD 7192A2 The common stock of TNC is owned by a who77y owned subsidiary of AEP.see notes to Financial Statements beginning on page L-1.Jed December 31.2001 2000 thousands) | |||
;122,588 $113,242 12,310 27,450 28,824 104$1I0,7=0 18,000 104 D-5 AEP TEXAS NORTH COMPANY Balance Sheets December 31, 2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Allowance for Uncollectible Accounts Fuel Inventory Materials and Supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS See Notes to Financia7 Statements beginning on page L-1.$ 353,087 254,483 445,486 111,679 37.012 1,201,747 521.792 679 955 1,213 2.248 1,219 62,660 43,632 (5,041)12,677 9,574 6,829 4,130 1,070 136.750 45,097 11 912$877.175$ 443,508 250,023 431,969 112,797 22.575 1,260,872 546.162 714,710 24.933* 8.327 2,454 18,720 8,656 (196)8,307 11,190 10,240 966 60,337 54,122 2.446_$_8_64,875 D-6 AEP TEXAS NORTH COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock $25 Par value: Authorized 7,800,000 Shares outstanding 5,488,560 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred Stock Not subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
short-term Debt Affiliates Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES see Notes to Financia7 statements beginning on page L-1.$137,214 2,351 (30,763)71.942 180,744 2,367 132. 500 28, 861 125,000 80,407 32,714 76,217 117 3,697 2,776 3,801 17.414 342,143 117, 521 21.510 557 50,972$137, 214 2,351 105.970 245,535 2,367 220,967 468.869 6,296 35,000 50,448 33,782 11,388 4,191 17,358 4,762 12,402 9. 824 179 155 145.049 22,781 52 250 37.475$87,17 D-7 AEP TEXAS NORTH COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income (Loss)Adjustments to Reconcile Net Income to Net Cash Flows From operating Activities: | |||
Depreciation and Amortization writedown of Utility Assets writedown of wind Farm Assets Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: | |||
Construction Expenditures sales Proceeds and other Net Cash used For Investing Activities FINANCING ACTIVITIES: | |||
Retirement of Long-term Debt change in short-term Debt Affiliated (net)Change in Advances from Affiliates (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net Cash Flows From (used For) Financing Activities | |||
$(13,677) | |||
$ 12,310 $ 27,450 43,620 38,154 4,744 (12,275)(1,271)(1,127)(74,071)(2,754)(6,829)63,761 (13,661)14,169 (16,928)16, 514 38. 369 (43,563)150 (43,413)50,705 (11,891)(1,271)(3,506)24,844 3,187 (42,604)(1,543)32,505 (1,432)11,056 72. 360 (39,662)(127)(39.789)55,172 8,164 (1,271)2,590 (1,445)8,478 28,393 6,443 (53,841)15,465 2,549 (3.869)94,278 (64,477)(64,477)(130,799)125,000 29,959 (20,247)(104)3 809 (8,130)(28,824)(104)(37,058)(48,000)37,170 (18,000)(104)(28.934)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents at Beginning of Period Cash and cash Equivalents at End of Period (1,235)2,454$-1,2-19 (4,487)6.941 i__2,54 867 6.074 Supplemental Disclosure: | |||
Cash paid (received) for interest net of capitalized amounts was $19,934,000 | |||
$19,279,000 and$19,088,000 and for income taxes was $15,544,000, $21,997,000 and ($906,000) in 2002, 2001 and 2000 respectively. | |||
see Notes to Financia7 statements beginning on page L-1.D-8 AEP TEXAS NORTH COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) | |||
$180.744 S245.535 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 810,000 Call Price December 31, Number of Shares Redeemed Series 2002 Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption: | |||
4.40% $107 --1 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 Statements beginning on page L-1.shares outstanding December 31. 2002 23,672 2,367 2,367 88,190 44,310 132. 500 211,657 44,310 (35 000)220.967 D-9 AEP TEXAS NORTH COMPANY Schedule of LonQ-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousaniis-Y | |||
% Rate Due 6-7/8 2002 October 1 S -7 2004 October 1 18,469 6-1/8 2004 February 1 24,036 6-3/8 2005 October 1 37,609 7-3/4 2007 June 1 8,151 unamortized Discount (75)Q8 S 35,000 40,000 40,000 72,000 25,000 (343)i2IL-6S Under the terms of the installment purchase contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) 2003 $ -2004 42,505 2005 37,609 2006 -2007 8,151 Later Years 44 310 Principal Amount 132,575 Less: unamortized Discount C75)Total S First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due Red River Authority of Texas: 6.00 2020 June 1 December 31.2002 2001 (in thousands) 544310 S44,31 D-10 AEP TEXAS NORTH COMPANY Index to Combined Notes to Financial Statements The notes to TNC s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to TNC. The combined footnotes begin on page L-1.Combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued operations Note 12 Asset Imapairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of credit and Sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Jointly owned Electric utility Plant Note 28 Related Party Transactions Note 29 D-11 i INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas North Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 D-1 2 APPALACHIAN POWER COMPANY AND SUBSIDIARIES I APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data I .n" 11 IdnIA IJ .IIU 1* J.1 ... I -.----2002 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Gain Net Income Preferred stock Dividend Requirements Earnings Applicable to common Stock$1,814,470 1,512,407 302,063 20,106 116.677 205,492 205,492 2.897$ 202,195 2001$1,784,259 1.509.273 274,986 6,868 120,036 161,818 161,818 2.011$ 159&0QZ 2000 (in thousands) | |||
$1,759,253 1.558.099 201,154 11,752 148.000 64,906 8.938 73,844 2,504 1999$1,586,050 1,344,814 241,236 8,096 128.840 120,492 120,492 2.706 1998$1,672,244 1.443.701 228, 543 (8,301)126.912 93,330 93,330 2.497 December 31, 2002 2001 2000 (in thousands) | |||
BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant 1999$5,262,951 2.079.490$5,895,303 2.424.607$5,664,657 | |||
: 2. 296. 481$5,418,278 | |||
: 2. 188. 796 3229 ,482$6.522 l 9S 1998$5,087,359 1.,984. 856 SI-1MA61 14.35Z2 Total Assets Common Stock and Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Total Cumulative Preferred Stock_4 &62.7 847 V4,047,038 | |||
$ 977,700 (72,082)260,439 ,166 Q5Z$ 976,244 (340)150, 797 I 1,12-6 7 0-$ 975,676 120, 584$1.,096,260Q | |||
$ 974,717 175. 854$ 924,091 179.461$103A52$ 17,790 $ 17,790 10.860 10,860$ 17,790 10,860$ 28.650$1,605,818 | |||
$ 18,491 20,310$1__3 Oi t1<6 65,$ 19,359 22.310 Long-term Debt (a)obligations under Capital Leases (a)Total Capitalization And Liabilities IL,55-6-55-9 | |||
_$It55L455 Si__5d751z L-3i,5&89 t{A,621T4~ | |||
$ 46,281$ 64,645$4Z482,78$65 57255$4I,Q4ZQ38 (a) Including portion due within one year.E-1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operation APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 retail customers in southwestern Virginia and southern West Virginia. | |||
APCo, as a member of the AEP Power Pool, shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
APCo also sells wholesale power to municipalities. | |||
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs.The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs.Results of Operations Net Income increased | |||
$44 million or 27% in 2002 due to higher retail sales resulting from increased generation, weather related electricity demands and reductions in Maintenance expense. Most significantly, the Mountainer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased | |||
$10 million as a result of a reduction in trading incentive compensation recorded in Nonoperating Expenses offset in part by decreased power trading gains recorded in Nonoperating Income.Net Income increased | |||
$88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000.In February 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in net income was growth in and strong performance by the wholesale electricity business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales.Operating Revenues Operating Revenues increased | |||
$30 million or 2% in 2002 as a result of weather related demand and increased generation resulting from availablility of plants previously down for maintenance coming back online. An increase of $25 million, or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power Pool transactions. | |||
Changes in components of revenues were as follows: Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Amount % Amount %$16.0 2 S(11.7) (1)(1.0) -20.1 3 wholesale El ectri ci ty*Energy Delivery*Sales to AEP Affiliates Total Revenues 15.2 5302 9 2 16.6 L25 0 11 1*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Operating Revenues for 2002 increased as a result of an increase in generation and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in residential and commercial sales due to warmer weather during July and September. | |||
Sales to AEP affiliates increased for the year due to an E-2 increase in generation capacity and power available to be delivered to AEP Power Pool.These increases were partially offset by flat industrial sales as recessionary conditions continued into 2002.The year 2001 saw a decrease in kilowatt hour sales to industrial customers. | |||
This decrease was due to the economic recession. | |||
In the fourth quarter, sales to residential and commercial customers declined, reflecting recession-related reductions in demand.The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP Power Pool transactions. | |||
As the quantity of energy sold by the AEP Power Pool rose, APCo s contribution of energy to the Pool rose, accounting for the increase in APCo s revenues from Sales to AEP Affiliates. | |||
Operating Expenses Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Power expenses were offset by decreases in power purchases from AEP Affiliates due to increases in APCo generation and availability as plants previously down for maintenance resumed operations. | |||
The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity purchased power expense and depreciation and amortization expenses.Changes in the components of Operating Expenses are as follows: Increase (Decrease) | |||
From Previous Year (dolTlars in millions)2002 2001 Amount % Amount %Fuel S 79.4 23 S (17.6) (5)of an increase in APCo generation. | |||
Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability in 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. | |||
Wholesale Electricity Purchases increased for 2002 as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. Electricity purchased power expense increased in 2001 due to increases in wholesale electricity prices and as a result of the previously mentioned plant outages.The decrease for 2002 in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability. | |||
Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo s MLR.Other Operation expense increased in 2002 mainly due to severance expenses related to the sustained earnings initiative plan, a reduction in the gains recorded on the dispositions of S02 emission allowances, and increased insurance premiums and other employee benefit costs. These increases were offset by reduced trading overhead expenses as a result of reduced staffing and weaker market conditions; a decrease in transmission equalization charges caused by a reduction in APCo s MLR ratio; and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. | |||
Additionally, the decrease was the result of a gain recorded on the disposition of S02 emission allowances offset in part by increased wholesale power trading incentive compensation expense.The decrease in Maintenance expense in 2002 is primarily due to previously discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in the year 2001.wholesale Electricity Purchases 15.0 36 AEP Affiliate Purchases (112.3) (32)other operation 8.9 3 Maintenance (10.2) (8)Depreciation and Amortization 8.9 5 Taxes other Than Income Taxes (4.6) (5)Income Taxes 18.0 19 Total __3.1 -17.4 70 (8.9) (3)(18.6) (7)7.9 -6 17.3 11 (11.8)(34. 5)(11)(27)(3)Fuel expense increased for 2002 as a result E-3 Depreciation and Amortization expense increased during 2002 due to increased amortization for the net generation-related regulatory assets related to the Companys West Virginia jurisdiction which were assigned to the distribution portion of the Companys business and are being recovered through regulated rates. Investment in production plant in service, primarily equipment related to emission control, contributed to the increase in depreciation and amortization expense.Depreciation and Amortization expense increased in 2001 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets in the Virginia and West Virginia jurisdictions. | |||
Additional investments in distribution and transmission plant also contributed to the increases in depreciation and amortization expense in 2001. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. | |||
Consequently net generation-related regulatory assets were assigned to the energy delivery businesss regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates.trading gains driven by a decline in market prices. Nonoperating Expenses decreased as a result of decreased trading incentives. | |||
The increase in Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable increases in the level of activity in the wholesale business s trading transactions outside of the AEP System s traditional marketing area.Interest Charges Interest Charges for 2002 decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. | |||
Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000.The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily to a decrease in municipal license tax. The municipal license tax was replaced by the Virginia consumption tax. The municipal license tax was imposed on APCo and the Virginia consumption tax is imposed on the customer with APCo acting as collector agent.The decrease in Taxes Other Than Income Taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state.The increase in Income Taxes for 2002 was due to an increase in pre-tax income. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income.Nonoperating Income and Nonoperating Expenses The Nonoperating Income decrease for 2002 was due primarily to a decrease in net power E-4 | |||
'!APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates Total Operating Revenues OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total operating Expenses OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (BENEFIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY GAIN DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) | |||
NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS | |||
$1,'1.Year Ended December 3 2002 2001 (in thousands) | |||
)33,904 $1,017,938 594,089 595,036 186.477 171,285 314.470 1.784.259 430,963 57,091 234,597 269,426 122,209 189,335 95,249 113.537 1,512.407 302,063 29,278 11,783 (2,611)116.677 205,492 205,492 2.897 L.351,557 42,092 346,878 260,518 132,373 180,393 99,878 95. 584 1,509.273 274,986 49,507 41,500 1,139 120.036 161,818 161,818 2.011 2000$1,029,657 574,918 154.678 1.759.253 369,161 24,720 355,774 279,114 124,493 163,089 111,692 130.056 1.558.099 201,154 31,204 16,329 3,123 148.000 64,906 8.938 73,844 2.504 EARNINGS APPLICABLE TO COMMON STOCK-$ZLn-A0 Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
NET INCOME $205,492 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge (1,580)Minimum Pension Liability (70,162)COMPREHENSIVE INCOME $13,50 see Notes to Financia7 Statements beginning on page L-1.$161,818 $73,844 (340)S161,AI A E-5 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31.2002 2001 2000 (in thousands) | |||
$150,797 $120,584 $175,854 205.492 161,818 73,844 356.289 282.402 249,698 Retained Earnings January 1 Net Income Deductions: | |||
cash Dividends Declared: Common stock Cumulative Preferred Stock: 4-1/2% series 5.90% Series 5.92% Series 6.85% series Total cash Dividends Declared capital Stock Expense Total Deductions Retained Earnings December 31 See Notes to Financia7 Statements beginning on page L-1.92,952 801 278 364 94,395 1.455 95.850$260,4139-129, 594 801 278 364 131,037 568 131.605$150, 797 126,612 811 307 364 289 128,383 731 129.114 E-6 | |||
--APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmi ssion Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Mi scellaneous Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial Statements beginning on page L-1.$2,245,945 1,218,108 1,951,804 272,901 206.54 5 5 ,895,303 2,424.607 3,470.696 54.653 115,748 4,285 132,266 122,665 28, 629 (13,439)53,646 59,886 30,948 94,238 13.396 526.,520 395.,553 64. 677$2,093,532 1,222,226 1,887,020 257,957 203,922 5, 664 ,657 2. 296. 48.3. 368. 176 53. 736 119,638 13,663 113,371 63,368 11,847 (1,877)56,699 59,849 30,907 137,742 16.018 501.587 397. 383 42, 265 E-7 APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock No Par value: Authorized 30,000,000 shares outstanding 13,499,500 Shares Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareowner s Equity Cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Taxes Accrued Customer Deposits Interest Accrued Energy Trading and Derivative Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.$ 260,458 717,242 (72,082)260.439 1,166,057 17,790 10,860 1,738,854 2,933,561 173.438 155,007 39,205 141,546 98,374 29,181 26,186 22,437 69,001 79. 832 660.769 701.801 33.691 44.517 80,070$4,62L,847 | |||
$ 260,458 715,786 (340)150.797 1,126,701 17,790 10,860 1.476. 552 2.631.903 84,104 80,007 291,817 127,597 84,518 55,583 13,177 21,770 121,161 79.089 874.719 703. 575 38,328 60. 518 89, 638 A4-82, 25 E-8 APPALACHIAN POWER COMPANY AND SUBSIDIARIES consolidated Statements of Cash Flows Year Ended December 2002 2001 (in thousands) 31.2000 OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Power Supply Costs (net)Mark-to-Market of Energy Trading Contracts Provision for Rate Refunds Extraordinary Gain Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Revenue Refunds Accrued Incentive Plan Accrued Disputed Tax and Interest Related to COLI change in operating Reserves Rate Stabilization Deferral change in other Assets change in other Liabilities Net Cash Flows From Operating Activities INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From sales of Property and other Net Cost of Removal and Other Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Change in Advances From Affiliates Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net cash Flows used For Financing Activities | |||
$ 205,492 189,335 16,777 (4,637)6,365 (21, 151)(83,412)3,016 (41)27,805 (26,402)(858)(3,190)(43,337)14,948 280,710$ 161,818 180, 505 42,498 (4,765)1,411 (68,254)134,099 (19,957)35,592 (45,073)(7,675)(2,451)(5,358)19,418 (27.954)393. 854$ 73,844 163,202 8,602 (4,915)(84,408)(1,843)(4,818)(8,938)(166,911)18,487 (13,081)159,369 14,220 181 10,662 72,440 (19,770)75,601 (13,021)9.817 288. 720 (276, 549)1,074 (275.475)647,401 (315,007)(252,612)(92,952)(1.443)(14,613)(306,046)1,182 (8.434)(313.298)124,588 (175,000)(191,495)300,204 (129,594)(1.443)(72.740)(199,285)159 (7.500)(206. 626)74,788 (9,924)(136,166)68,015 (8,387)(126,612)(1.938)(140,224)Net Increase (Decrease) in cash and Cash cash and cash Equivalents January 1 cash and cash Equivalents December 31 Equivalents (9,378)13.663$ 4,285 7,816 5 $ 847 (58,130)63.977$ A Z supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000 and$124,579,000 and for income taxes was $125,120,000, $56,981,000 and $63,682,000 in 2002, 2001 and 2000, respectively. | |||
There were no noncash acquisitions under capital leases in 2002. In 2001 and 2000, non cash acquisitions under capital leases were $2,510,000 and $14,116,000, respectively. | |||
see Notes to Financia7 Statements beginning on page L-1.E-9 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
S1.166.057 | |||
$1.126.701 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: No par value -authorized shares 8,000,000 call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption (b): 4-1/2% $110 6 -7,011 subject to Mandatory Redemption (b): 5.90% cc) --10,000 5.92% Cc) _ _ -shares Outstanding December 31. 2002 177,899 47,100 61, 500 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Junior Debentures other Long-term Debt Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 17.790 4,710 6.150 10.860 489,697 235,027 1,166,609 2,528 (155.007)1.738.854 17.790 4,710 6.150 10.860 639,365 234,904 518,247 161, 507 2,536 (80.007)1.476.552 52,631,903 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends. | |||
The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.(b) The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date.(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90%series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirement. | |||
see Notes to Financial statements beginning on page L-1.E-1 0 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 7.38 2002 7.40 2002 6.65 2003 6.85 2003 6.00 2003 7.70 2004 7.85 2004 8.00 2005 6.89 2005 6.80 2006 8.50 2022 7.80 2023 7.15 2023 7.125 2024 8.00 2025 unamortized Total August 15 '-December 1-May 1-June 1-November 1-September 1-November 1-May 1-June 22-March 1-December 1-May 1-November 1-May 1-June 1 Discount S -30,000 21,000 50,000 50,000 30,000 100,000 70,000 30,237 20,000 45,000 45,000-1C 540)$ 50,000 30,000 40,000 30,000 30,000 21,000 50,000 50,000 30,000 100,000 70,000 30, 237 20,000 45,000 45,000 (1.872)M69,36 Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands) | |||
First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
X Rate Due (a) 2003 August 20 S 125,000 5125,00 7.45 2004 -November 1 50,000 50,00 4.80 2005 June 15 450,000 -4.32 2007 November 12 200,000 -6.60 2009 -May 1 150,000 150,00 7.20 2038 -March 31 100,000 100,00 7.30 2038 -June 30 100,000 100,00 unamortized Discount 8 391 6.75 Total VIA609 S51,2 (a) A floating interest rate is determined monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, respectively. | |||
0 0 0 0 0 z Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds, by governmental authorities as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due Industrial Development Authority of Russell county, Virginia: Junior debentures outstanding were as follows: December 31.2002 2001 (in thousands) 8-1/4% Series A due 2026 September 30 8% Series B due 2027-March 31 unamortized Discount Total S -S 75,000 90,000 (3 .493)U161, 50 7.70 2007 -November 1 S 17, 500 5.00 2021 -November 1 19,500 Putnam County, West Virginia: S 17, 500 19, 500 At December 31, 2002, future annual long-term debt payments are as follows: 5.45 2019 -June 1 41 6.60 2019 -July 1 3 Mason County, West Virginia: 7-7/8 2013 -November 1 1 6.85 2022 -June 1 4 6.60 2022 -October 1 5 6.05 2024 -December 1 3 unamortized Discount Total 0,000 40,000 0,000 30,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 155,007 121,008 530,010 100,011 217,513 782. 216 1,905,765 (11,904)0,000 0,000 0,000 0,000 1. 973)10,000 40,000 50,000 30,000 (2 096)1234.90A E-1 1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to APCO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to APCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investments Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note Note Note Note Note Note Note 17 18 20 22 23 24 29 E-1 2 INDEPENDENTAAUDITORS REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian PowerCompanyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance aboutwhetherthe financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 E-1 3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable to common Stock$1,400,160 1180T3 81 219,779 15,263 53. 869 181,173 181,173$1,350,319 1.098.142 252,177 7,738 68.015 191,900 (30.024)161,876$1,304,409 1.108.532 195,877 5,153 80,828 120,202 (25. 236)94,966$1,190,997 968.207 222,790 2,709 75. 229 150,270 150,270 2.131$18 139$1,187,745 975, 534 212,211 (1,343)77.824 133,044 133,044 2.131£ 410Q9f 1.095$ 160.781£__1798JA1 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$3,467,626 1.465.174£2_Q02 ,452$Z,153,240 | |||
$3,354,320 1.377.032$1,977,288 3$Z.2 "388$3,266,794 1.299.697$3,151,619 1.210.994£1,40,625$ &08Q8123$3,053,565 1.134. 348$1,912,=21 | |||
_$13 X&ZL42i Common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$ 616,410 (59,357)290.611$_847 7 604$ 615,395 176.103=$ 191 9,AH$ 614,380 99.069$ 713,449$ 613,899 246, 584$860.,483$ 613,518 186.441$Z 79R9,9 cumulative Preferred stock -subject to Mandatory Redemption (a)Long-term Debt (a)Obligations under Capital Leases (a)Total Capitalization and Liabilities L$ L6 1 Q6Z R 2$ i_ 4 Q$L 72293&$ 252i0f$L 25,000$ _ 9 2 4 .5 4 5 L Z &S 4_0ZZ0 L A42L3Z$3,87,491 (a) Including portion due within one year.F-1 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Manaaement s Narrative Analysis of Results of ODerations Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 689,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
CSPCo also sells wholesale power to municipalities. | |||
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each companies percentage share of AEP Power Pool revenues and costs.Results of Operations Net Income increased | |||
$19 million or 12% in 2002 due to reduced interest charges and a$30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio excise taxes stranded by Ohio deregulation offset by higher operating expenses.Operating Revenues Operating Revenues increased in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. | |||
Changes in the components of Operating Revenues were: Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount %Retail* S51 8 wholesale Marketing 3 2 unrealized MTM (4) (22)Other 1 3 wholesale Electricity* | |||
51 6 Energy Delivery* | |||
9 2 Sales to AEP Affiliates (10) (15)Total Revenues $5Q 4* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 35%. For the fall season, heating degree days increased 34%. This reflects a return to more normal weather conditions since the weather experienced in 2001 was abnormally mild.Operating Expenses Operating Expenses increased in 2002 mainly as a result of purchased power, operating expenses and state taxes.Changes in the components of Operating Expenses were: Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount X Fuel wholesale Purchased Power AEP Affiliates Purchased Power other operation Expenses Maintenance Expense Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total$10 4 18 18 (2)4 25 5 6 37 6 8 (4)3 22 5 7 10%by a coal Fuel cost increased as a result of a increase in generation partially offset slight cost decrease per ton of consumed.Wholesale Purchased Power increased in 2002 due to increased purchases from third F-2 parties for resale to wholesale customers and to meet internal demand.Expenses related to AEP Affiliates Purchased Power increased due to greater system pool capacity charges.The increase in Other Operation expenses was attributable to a number of factors: higher OPEB post retirement costs as a result of higher medical cost and lower investment performance, 2002 Sustained Earnings Initiative Expenses, and the 2001 reversal of a quality of service liability accrual. The increase was partially offset by a reduction in energy trading overheads reflecting reduced marketing activity.The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in property taxes and a full year of the state excise tax which replaced the state gross receipts tax during 2001.The increase in Income Taxes is predominately due to an increase in state taxes as a result of the State of Ohio s tax legislation resulting from utility deregulation. | |||
This increase was offset in part by a decrease in federal taxes due to a decrease in pre-tax operating income.Nonoperating Income and Nonoperating Expense The decrease in Nonoperating Income in 2002 is due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System s traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. CSPCo s share of the AEP Power Pool s gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in Nonoperating Income. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand.The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy trading incentive compensation. | |||
Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax nonoperating income.Interest Charges Interest Charges decreased in 2002 primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.F-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income 2002 Year Ended December 31.2001 (in thousands) 2000 OPERATING REVENUES: wholesale Electricity Energy Delivery sales to AEP Affiliates Total operating Revenues OPERATING EXPENSES: Fuel Purchased Power: Wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME S 850,680 492,278 57,202 1.400.160 185,086 15,023 310,605 237,802 60,003 131,624 136,024 104.214 1,180.381 219,779 26,360 S 799,589 483,219 67,511 1,350.319 175,153 10,957 292,199 219,497 62,454 127,364 111,481 99.037 1 098.142 252,177 32,756 21,095 3,923 68,015 191,900 (30.024)161,876 1.095$ 856,998 398,046 49. 365 1,304.409 189,155 9,879 287,750 219,840 69,676 99,640 123,223 109, 369 1.108, 532 195,877 20,580 8,070 7,357 80.828 120,202 (25, 236)94,966 1.783$ ~93,13 NONOPERATING EXPENSES 4,308 NONOPERATING INCOME TAX EXPENSE INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 6,789 53 869 181,173 181,173 1.332$ 179, 841 Consolidated Statements of Comprehensive Income 21 Year Ended December 31.'02 2001 2000 (in thousands) 1,173 $161,876 $94,966 NET INCOME 18: OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability (M COMPREHENSIVE INCOME $12 The common stock of the CSPCo is who7ly owned by AEP.See Notes to Financial Statements beginning on page L-1.(267)9. 090)3261,B 6 594--9-U F-4 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eaminqs Year Ended December 31.2002 2001 2000 (in thousands) | |||
Retained Earnings January 1 Net Income Deductions: | |||
cash Dividends Declared: Common Stock Cumulative Preferred Stock Total cash Dividends capital stock Expense Total Deductions Retained Earnings December 31$176,103 181,173 357,276 7% series Declared 65,300 350 65,650 1.015 66.665$290,611.$ 99,069 161.876 260.945 82,952 875 83,827 1.015 84.842$i176,13$246,584 94.966 341.550 240,600 1.400 242,000 481 242.481 SL32Pa9 see Notes to Financial Statements beginning on page L-1.F-5 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation | |||
$1,582,627 413,286 1,208,255 165,025 98.433 3,467,626 1.465,174 NET ELECTRIC UTILITY PLANT 2,002X452 OTHER PROPERTY AND INVESTMENTS 35.759 LONG-TERM ENERGY TRADING CONTRACTS 77.810$1,574,506 401,405 1,159,105 146,732 72.572 3,354,320 1,377.032 1,977.288 40.369 73. 310 12,358 41,770 63,470 16,968 (745)20,019 38,984 7,087 84,323 28.733 312.967 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Energy Trading Contracts Prepayments and other Current Assets TOTAL CURRENT ASSETS 1,479 31,257 49,566 54,518 22,005 (634)24,844 40,339 12,671 63,348 7.308 306.701 REGULATORY ASSETS 257.682 DEFERRED CHARGES 72,836$2,753,240 262.267 56,187$2,722,388 TOTAL ASSETS see Notes to Financia7 Statements beginning on page L-1.F-6 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock No Par value: Authorized 24,000,000 shares outstanding 16,410,426 shares Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity cumulative Preferred stock subject to Mandatory Redemption Long-term Debt -General Long term Debt Affiliated companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year General Long-term Debt Due within One Year Affiliated Companies short-term Debt Affiliated Companies Advances from Affiliates Accounts Payable General Accounts Payable Affiliated companies Taxes Accrued Interest Accrued Energy Trading Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 41,026 575,384 (59,357)290.611 847,664 418,626 160,000 1,426.290 95,460 43,000 290,000 89,736 81,599 112,172 9,798 46,375 36,790 709.470 437.771 33.907 29.926 20.416$Za53 24Q$ 41,026 574,369 176,103 791,498 10,000 571,348 1.372.846 36,715S 20,500 200,000 181, 384 60,689 83,697 116,364 10,907 72,082 36, 305 781,928 443, 722 37.176 37.101 12.900£tZ722 za83 F-7 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark to Market of Energy Trading Contracts Extraordinary Loss Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities S 181,173 131,753 23,292 (3,269)(16,667)(3,992)(6,180)(5,584)26,949 (8,027)(22,448)297,000$ 161,876 128,500 24,108 (4,058)(44,680)30,024 19,987 (7,780)2,551 (16,249)(42,066)(18,769)233,444 S 94,966 100,182 (4,063)(3,482)5,352 (3,393)25,236 (29,737)11,957 38,479 81,284 39,483 (121,115)132.44 367,590 INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From Sales and Leaseback Transactions and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
change in Advances from Affiliates (net)Issuance of Affiliated Long-term Debt Retirement of Preferred Stock Retirement of General Long-term Debt Retirement of Affiliated Long-term Debt Change in short-term Debt (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows used For Financing Activities (136,800) | |||
(132,532)730 (136,070)(212,641)160,000 (10,000)(133,343)(200,000)290,000 (65,300)(525)(171 809)10.84 (121.691)92,652 200,000 (5,000)(314,733)(82,952)(962)(110.995)(127,987)1. 560 (126.427)88,732 (10,000)(25,274)(45,500)(240,600)(1.575)(234,217)Net Increase (Decrease) in cash and cash Cash and cash Equivalents January 1 cash and Cash Equivalents December 31 Equivalents (10,879)12.358 3-1"79 758 11,600 S-1 3-5-8 6,946 4.654 S-II&M0 supplemental Disclosure: | |||
cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000 and$68,506,000 and for income taxes was $117,591,000, 80,485,000 and $81,109,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were S1,o09,000 and $10,777,000 in 2001 and 2000, respectively. | |||
See Notes to Financial Statements beginning on page L-1.F-8 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of CaDitalization December 31.2002 2001 (in thousands) | |||
COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:. S100 par value authorized shares 2,500,000 525 par value -authorized shares 7,000,000$ 847.664 S 791.493 series Number of shares Redeemed Year Ended December 31, 2002 2001 2000 shares outstanding December 31, 2002 Subject to Mandatory Redemption: | |||
7.00% 100,000 50,000 100,000 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior unsecured Notes Notes Affiliated Junior Debentures Less Portion Due within one Year Total Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 222,797 91,275 147,554 160,000 ( 43.000)578.626 S1L 42,9 243,197 91,220 147,458 200,000 109,973 (220. 500)571. 348 1S1,7-21, A-C see Notes to Financial statements beginning on page L-1.F-9 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
December 31.2002 2001 (in thousands) | |||
% Rate Due 7.25 2002 7.15 2002 6.80 2003 6.60 2003 6.10 2003 6.55 2004 6.75 2004 8.70 2022 8.55 2022 8.40 2022 8.40 2022 7.90 2023 7.75 2023 7.60 2024 unamortized Total October 1 S -November 1 May 1 13,000-August 1 25,000 November 1 5,000 March 1 26,500 May 1 26,000 July 1 2,000 August 1 15,000 August 15 14,000 October 15 13,000 May 1 40,000 August 1 33,000 May 1 11,000 Discount (703)$ 14,000 6,500 13,000 25,000 5,000 26, 500 26,000 2,000 15,000 14,000 13,000 40,000 33,000 11,000 (803)% Rate Due 6.85 2005 6.51 2008 6.55 2008 unamortized Total October 3 $ 36,000 February 1 52,000 June 26 60,000 Discount (446)S 36,000 52,000 60,000 (542)Notes payable to parent company were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate (a)6.501%Total Due 2002 -Sept 25 S -2006 May 15 160.000 S 160,00$200,000 First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: | |||
December 31, 2002 2001 (in thousands)(a) Redemed 9/25/02 Junior debentures outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due 8-3/8 2025 7.92 2027 unamortized Total Sept 30 S -March 31 -Discount -5~S 72,843 40,000 (2.870)At December 31, 2002, future annual long-term debt payments are as follows:% Rate Due 6-3/8 2020 -December 1 $48,550 6-1/4 2020 -December 1 43,695 unamortized Discount (970)Total 191,m$48,550 43,695 (1.02 5)2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 43,000 52,500 36,000 160,000 332.245 623,745 (2.119)5621 Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant.F-1 0 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to CSPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to CSPCo.The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer Choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Jointly owned Electric Utility Plant -Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 28 Note 29 F-1 I INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company s management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 F-1 2 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY Selected Consolidated Financial Data AND SUBSIDIARIES Yea 2002 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income (Loss)Nonoperating Items, Net Interest charges Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$1,526,764 1.375,575 151, 189 16,726 93.923 73,992 4.601 2001$1, 526,997 1.367,292 159,705 9,730 93. 647 75,788 ir Ended December 31.2000 1999 (in thousands) | |||
$1,488,209 1.522.911$1,351,666 1.243,014 (34,702) 108,652 1998$1,405,794 1,239,787 166,007 (839)68.540 96,628 4.824 9,933 107. 263 (132,032)4,530 80.406 32,776 4.621 4,885$ 71,167$ 27,891 2002 2001 December 31, 2000 (in thousands) | |||
_ _ _ _1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$5,029,958 2,568.604$2,.461,3~54 i48L28719$4,923,721 2.436.972$2,486, 749$4,871,473 | |||
: 2. 280.521$2.,590.,952 | |||
$4,770,027 2.194.397$2,5575,30 | |||
$4,631,848 2.081, 355$2.,550.,493 Total Assets common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption (a)Total Cumulative Preferred stock$ 915,144 (40,487)143.996$ 789,800 (3,835)74,605$ 789,656 3,443$ 789,323 166.389$ 789,189 2 53.154$108,11 $ 8,36 S 793,099 6 $ 9,552, $1 273 S 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 64.945$163,046$1, 617,062 64, 945 11,652-Q&Z 64,945$1,388,939 64.945$£ 74.193$1,324, 3-26 68.445$ 7-7.718 Long-term Debt (a)obligations under capital Leases (a)$ 50,848$ 61L933$-163,173$ 187,965$ 186,427 Total capitalization And Liabilities A 58L7191 4. 394 062$5,774 108$4,575,210 (a) Including portion due within one year.G-1 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 571,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. | |||
As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers. | |||
I&M also sells wholesale power to municipalities and electric cooperatives. | |||
The cost of the AEP Power Pool s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs.maintenance costs incurred as part of planned and unplanned outages at Cook Plant and Rockport Plant.During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection (see Note 5).As a result of costs incurred in 2000 to restart the Cook Plant and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, Net Income increased in 2001 by $208 million. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including l&M, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. The deferrals were expensed and impacted Net Income in 2000.Operatina Revenues Increase Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. | |||
AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo s Rockport Plant capacity to KPCo through 2004. The KPCo agreement extends until December 31, 2009 for Rockport Unit I and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. | |||
Therefore, l&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.Results of Operations During 2002 Net Income decreased by $2 million due to increased operations and Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase reflects increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in Operating Revenues: Increase (Decrease) | |||
From Previous Year (dollars in milions)2002 2001 Amount % Amount %Retail* $ 28.2 Marketing | |||
===2.6 other=== | |||
2.6 Total wholesale Electricity 33.4 Energy Dellvery* | |||
===7.3 sales=== | |||
to AEP Affiliates (40 Total 4 1 6 S (2.3)(12.0)5 .0 N.M (4)13 3 (9.3) (1)2 3.4 1) (16) 44.7) N.M. 3.3 21 3 N.M. = Not Meaningful | |||
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.G-2 The increase in Operating Revenues in 2001 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power l&M could sell to its affiliates in the AEP Power Pool.Operating Expenses Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000. The changes in the components of Operating Expenses were: Plant nuclear units for restart with their return to service in 2000. Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002.The increase in Depreciation and Amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of l&M s share of deferred merger costs.Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment of amounts recorded in December 2000 to actual expenses.Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income. The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income.Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Fuel I wholesale Electricity Purchases AEP Affiliate Purchases Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total I Amount % Amount %'0(10.6) (4) $ 39.2 19 4.7 25 4.9 36 (4.5)13.6 24.3 3.8 (7.8)(15.2)w--(2)3 19 (27.2) (10)(147.7) (25)(92.6) (42)2 9.3 6 (12) 4.9 8 (28) 53.6 N.M.1 ) (10)Nonoperating Income.Expenses and Income Taxes Nonoperating N.M. = Not Meaningful Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. | |||
The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs.The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21 %.Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. | |||
The decrease in Other Operation and Maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP s traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP s traditional marketing area.Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders incentive compensation. | |||
Nonoperating Expenses increased in 2001 due to increased trading overheads and traders incentive compensation. | |||
The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income.Interest Charges The decrease in 2001 Interest Charges reflects the recognition in 2000 of deferred G-3 interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998. | |||
G-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME (LOSS)NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$ 990,905 321,721 214,138 1. 526. 764 239,455 23,443 233,724 462,707 151,602 168,070 57,721 38. 853 1. 375. 575 151,189 93,739 71,029 5,984 93. 923 73,992 4.601$ 957,548 314,410 255.039 1,526.997 250,098 18,707 238,237 449,115 127,263 164,230 65,518 54.124 1. 367,292 159,705 97,810 83,037 5,043 93 647 75,788 4.621 S 71,167$ 966,882 311,019 210.308 1.488.209 210,870 13,785 265,475 596,861 219,854 154,920 60,622 524 1.522.911 (34,702)76,499 62,377 4,189 107.263 (132,032)4,624$ 315,2656)Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
NET INCOME (LOSS) $ 73,992 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 3,835 Cash Flow Power Hedge (286)Minimum Pension Liability (40,201)COMPREHENSIVE INCOME (LOSS) $ 37, see Notes to Financia7 statements beginning on page L-1.$75,788 $(132,032) | |||
(3,835)-Z2 5113Z-02)G-5 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings 2002 Year Ended December 31.2001 (in thousands) 2000 Retained Earnings January 1 Net Income (Loss)Deductions: | |||
cash Dividends Declared: Common stock cumulative Preferred stock: 4-1/8% series 4.56% Series 4.12% series 5.90% series 6-1/4% series 6.30% series 6-7/8% series Total Cash Dividends Declared capital stock Expense Total Deductions | |||
$ 74,605 73, 992 148, 597 S 3,443 75.788-79.231$ 166,389 (132.032)34. 357 229 66 52 897 1,203 834 1.186 4,467 134 4.601 229 66 72 897 1,203 834 1.186 4,487 139 4.626 26,290 230 66 74 897 1,203 834 1,186 30,780 134 30.914 Retained Earnings December 31 $143 See Notes to Financia7 statements beginning on page L-1.S 74,6L05$3 1 A443 G-6 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 (in thousand 2001 S)ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General (including nuclear fuel)Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$2,768,463 971,599 921,835 220,137 147.924 5,029,958 2.568,604 2.461. 354$2,758,160 957,336 900,921 233,005 74.299 4,923,721 2,436.972 2.486.749 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870.754 834,109 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83, 265 OTHER PROPERTY AND INVESTMENTS 120,941 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading and Derivative Contracts Accrued Utility Revenues Prepayments and other TOTAL CURRENT ASSETS 3,237 191,226 67,333 122,489 30,468 (578)32,731 95,552 68,148 6,511 11,899 629.016 127.977 16,804 46,309 60,864 31,908 25,398 (741)28,989 91,440 108,895 2,072 6.497 418.435 REGULATORY ASSETS 348.212 408,927 DEFERRED CHARGES 73.649 34,967 TOTAL ASSETS$4,58,191 see Notes to Financia7 Statements beginning on page L-1.G-7 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
common Stock -No Par value: Authorized | |||
-2,500,000 shares outstanding | |||
-1,400,000 Shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION | |||
$ 56,584 858,560 (40,487)143 996 1,018,653 8,101 64,945 1.587,062 2,678, 761 620,672 138.965 759.637$ 56,584 733,216 (3,835)74.605 860,570 8,736 64,945 1. 3123082 2.246. 333 600,244 87,025 687,269 OTHER NONCURRENT LIABILITIES: | |||
Nuclear Decommissioning other TOTAL OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within one Year Accounts Payable General Accounts Payable -Affiliated Companies Taxes Accrued Interest Accrued obligations under capital Leases Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES 30,000 125,048 93,608 71,559 21,481 8,229 48,568 92. 822 491,315 340,000 86,766 43,956 69,761 20,691 10,840 93,413 76 486 741.913 DEFERRED INCOME TAXES 356,197 400,531 DEFERRED INVESTMENT TAX CREDITS 97,709 105,449 DEFERRED GAIN ON SALE AND LEASEBACK | |||
-ROCKPORT PLANT UNIT 2 73,885 77, 592 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32, 261 42,936 92,039 REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES | |||
$4 58iLL191.$4,3940Q6Z See Notes to Financia7 Statements beginning on page L-1.G-8 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: | |||
Net Income (Loss)Adjustments for Noncash Items: Depreciation and Amortization Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net)Amortization of Nuclear Outage Costs Deferred Income Taxes Deferred Investment Tax credits Unrecovered Fuel and Purchased Power Costs Changes in Certain Current Assets And Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and Supplies Accrued utility Revenues Accounts Payable Taxes Accrued Mark-to-Market of Energy Trading and Derivatives Contracts Disputed Tax and Interest Related to COLI Regulatory Asset Trading Losses Regulatory Liability Trading Gains change in other Assets Change in other Liabilities Net cash Flows From Operating Activities | |||
$ 73,992 168,070 (26,577)40,000 (16,921)(7,740)37,501 (102,283)(7,854)(4,439)87,934 1,798 (9,517)(992)2,494 (28,233)21.001 228.234$ 75,788 166,360 418 40,000 (29,205)(8,324)37,501 64,841 (19,426)(2,072)(60,185)1,345 (62,647)8,493 34,293 (5,871)(5,102)236,207$ (132,032)163,391 5,737 40,000 (125,179)(7,854)37,501 (25,305)10,743 44,428 85,056 19,446 14,830 56,856 (17,914)(7,416)(68,160)37.309 131.437 INVESTING ACTIVITIES: | |||
Construction Expenditures Bu yout of Nuclear Fuel Leases Other Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES: | |||
capital Contributions from Parent Company Issuance of Long-term Debt Retirement of cumulative Preferred Stock Retirement of Long-term Debt change in Advances from Affiliates (net)change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and Cash Equivalents January 1 cash and cash Equivalents December 31 (167,484)1. 759 (165 .72 5)125,000 288,732 (424)(340,000)(144,917)(4.467)(76.076)(91,052)(92,616)1,074 (182.594)297,656 (44,922)(299,891)(4.487)(51.644)(171,071)587 (170.484)199,220 (314)(148,000)253, 582 (224,262)(26,290)(3. 368).50. 568 (13,567)16.804 1,969 11,521 14.835 3,314 l_6104 S 14, 835 Supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000 and$82,511,000 and for income taxes was $60,523,000, $100,470,000 and $73,254,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were $1,023,000 and$22,218,000 in 2001 and 2000, respectively. | |||
see Notes to Financial Statements beginning on page L-1.G-9 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
$1.018.653 S 860.570 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:$100 Par value -Authorized 2,250,000 shares$25 Par value -Authorized 11,200,000 shares call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not Subject to Mandatory Redemption-$100 Par: 4-1/8% 106.125 20 -3,750 4.56% 102 ---4.12% 102.728 6,326 -1,375 Subject to Mandatory Redemption-S100 Par(b): 5.90% (c) ---6-1/4% (c) ---6.30% (c) ---6-7/8% (d) ---shares outstanding December 31. 2002 55,369 14,412 11,230 152,000 192,500 132,450 172,500 5,537 1,441 1. 123 8.101 15,200 19,250 13,245 17.250 64.945 5,539 1,441 i1. 756 8.736 15,200 19, 250 13,245 174 950 64.945 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 174,245 264,141 Installment Purchase Contracts 310,336 310,239 senior unsecured Notes 747,027 696,144 other Lon -term Debt (e) 223,736 219,947 Junior Debentures 161,718 161,611 Less Portion Due within one Year (30.000) (340.000)Long-term Debt Excluding Portion Due within one Year 1.587,062 1.312,082 TOTAL CAPITALIZATION 4S2j1 SZ,2A33 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends (b) sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of these due dates. Shares previously purchased may be applied to meet the sinking fund requirement. | |||
cc) commencing in 2004 and continuing through 2008 I&M may redeem at $100 per share, 20,000 shares of the 5.90%series, 15,000 shares of the 6-1/4% series and 17,500 shares of? the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. The series are callable beginning November 1, 2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March 1, 2004 for the 6.30% series at $100 plus accrued dividends.(d) commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. callable at $100 per share plus accrued dividends beginning February 1, 2003.(e) Represents a liability for SNF disposal including interest payable to the DOE. See Note 9.See Notes to Financial Statements beginning on page L-1.G-10 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 7.60 2002 7.70 2002 6.10 2003 8.50 2022 7.35 2023 7.20 2024 7.50 2024 unamortized November 1 December 1-November 1-December 1 October 1 February 1 March 1 Discount.S 30,000 5 75,000 15,000 30,000 25.000 (75 5)$ 50,000 40,000 30,000 75,000 15,000 30,000 25,000 (859)The terms of* the installment purchase contracts require l&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date).Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) | |||
December 31.2002 2001 (in thousands) | |||
% Rate Due (a) 2002 6-7/8 2004 6.125 2006 6.45 2008 6.375 2012 6 2032 unamortized September 3 S -3uqy 1 150,000 December 15 300,000 November 10 50,000 November 1 100,000 December 31 150,000 Discount (2.973)S7AL 02$200,000 150,000 300,000 50,000 (3.856)% Rate Due City of Lawrenceburg, Indiana: 7.00 2015 April 1 S 25,000 5.90 2019 -November 1 52,000 city of Rockport, Indiana: (a) 2014 August 1 7.60 2016 March 1 6.55 2025 June 1 (b) 2025 June 1 4.90(c) 2025 June 1 city of Sullivan, Indiana: 5.95 2009 May 1 unamortized Discount I1 S 25,000 52,000 50,000 40,000 50,000 50,000 (a) A floating interest rate was determined quarterly. | |||
The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.Junior debentures outstanding were as follows: December 31.2002 2001-in thousands) 40,000 50,000 50,000 50,000% Rate Due 8.00 2026 7.60 2038 unamortized Total March 31 S 40,000 June 30 125,000 Discount (3 282)S161 71 S 40,000 125,000 (3.389)45,000 45,000 (1.664) (1 761)t3036 S1 3 (a) A variable interest rate was determined weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001.(b) In June 2001 an auction rate was established. | |||
Auction rates are determined by standard procedures every 35 days. The auction rate for 2002 ranged from 1.3% to 1.7% and averaged 1.5%. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9%to 4.9% in 2001 and averaged 3.3% during 2001.(c) Rate is fixed until June 1, 2007 (term rate bonds).Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 30,000 150,000 300,000 50,000 1.095.736 1,625,736 (8.674)51 617 06 G-1 I INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to combined Notes to Consolidated Financial statements The notes to I&M s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1.significant Accounting Policies Merger Nuclear Plant Restart Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and Sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 5 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 G-12 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America./sI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 G-13 KENTUCKY POWER COMPANY KENTUCKY POWER COMPANY Selected Financial Data Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Net Income$ 378,683 336.486 42,197 5,206 26.836$ 20,567$ 379,025 331. 347 47,678 1,248 27. 361$ 21,565$ 389,875 340.137 49,738 2,070 31.045 20,76i3$ 358,757 304.082 54,675 (327)28.918$ 2iA3A0$ 362,999 311.106 51,893 (1,726)28.491 kS _21,676 Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common Stock and Paid-in Capital Accumulated Other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$1,295,619 397, 304$1,164,676 | |||
$ 259,200 (9,451)48.269$1,128,415 384.104$ 744,311 S 999,048$ 209,200 (1,903)$1,103,064 360.648 S 742,416$1,494,543 | |||
$ 209,200 57.513 S_266,713$1,079,048 340.008$ 739.040$ 986.123$ 209,200 67.110$ 2 6,310$1,043,711 315. 546$ 728 165$ 921,3A7$ 199,200 71.,452 Si248 0-18 Lon -term Debt (a)Debt ( )3 963632$ 346-093 5-365.,782 L_3 68-838 obligations Under Capital Leases(a)Total Capitalization and Liabilities I1164. 676$1,494,543 | |||
$921,84 (a) Inc7uding portion due within one year.H-1 KENTUCKY POWER COMPANY Management s Narrative Analysis of Results of Operations KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in eastern Kentucky. | |||
KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
KPCo also sells wholesale power to municipalities. | |||
The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs.KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP s settlement restructuring agreement filed with the FERC becomes operative. | |||
The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Underthe unit power agreement, there is a demand charge for the right to receive the power, which is payable even it the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity.Results of Operations Net Income for 2002 decreased | |||
$1 million or 5%.Total Revenues were flat while increases in Operating Expenses, driven by expenses related to planned outages at the Big Sandy plant, were offset by comparable gains in net nonoperating income which benefited from decreases in trading incentive compensation. | |||
Changes in Revenues wholesale Electricity* | |||
Energy Delivery*Sales to AEP Affiliates Total Increase (Decrease) | |||
Year-to-Date (dollars in milions Amount %$13 6 j!) C(34)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Revenues in 2002 were comparable to those of last year. Increased sales to retail electricity customers reflecting warmer summer weather, colder days in late 2002, and increased fuel recovery revenues were offset by lower Sales to AEP Affiliates resulting from planned outages in 2002. KPCo s decreased generation was due to scheduled maintenance resulting in lower availability in the fourth quarter.Changes in Operating Expenses Increase (Decrease) | |||
Year-to-Date (dollars in millions)Amount %S(5.6) (8)-N.M.Fuel wholesale Electricity Purchases from AEP Affiliates other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Total Operating Expenses N.M. = Not Meaningful 2.8 (5.4)12.6.7.4-E4)2 (9)56 2 5 (4)2 Fuel expense decreased in 2002 as a result of planned fourth quarter outages at the Big Sandy H-2 plant for scheduled boiler maintenance. | |||
The 800 megawatt Unit 2, representing approximately 75%of the plants generation capacity, was off-line from mid-September through the end of the year, thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to meet demand during the planned outages at the Big Sandy plant.Other Operation expense decreased in 2002 due to reduced consumption of emission allowances due to the planned outage; reduced accruals for trading incentive compensation due to reduced trading activity; and improvements in transmission expense resulting from less wholesale activity and related transmission, and an increase in AEP transmission equalization credits. Underthe AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company s peak demand and investment. | |||
A decrease in KPCo s peak demand relative to its affiliates peak demand was the main reason for the increase in transmission equalization credits. These developments were offset in part by severance expenses related to a sustained earnings initiative (see Note 11).Nonoperating Income Taxes for 2002 have increased as a result of increases in pre-tax income for the year offset in part by prior-year tax return adjustments. | |||
Other Changes Nonoperating Income for 2002 decreased as a result of AEP s previously announced plan to reduce trading activity, and decreased margins on power trading activity outside of the AEP System s traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased in 2002 as a result of decreases in trading incentive compensation. | |||
Maintenance expense increased in 2002 primarily as a result of planned power plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for planned boiler overhaul and electric plant maintenance. | |||
The Company experienced marginal increases in overhead line maintenance expense.H-3 | |||
--KENTUCKY POWER COMPANY Statements of Income Year 2002 (in Ended December 31.2001 2000 thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES$218,665 132,054 27,964 378.683 65,043 29 133,002 52,892 35,089 33,233 8,240 8.958 336,486 42,197 7,863 753 1,904 26,836 20.567$205,476 131,183 42. 366 379.02 5 70,635 86 130,204 58,275 22,444 32,491 7,854 9. 358 331, 347 47,678 10,881 8,949 684 27. 361 La25=U6$226,708 121,346 41.821 389,875 74,638 1,940 127,707 52,495 25,866 31,028 7,251 19,212 340.137 49,738 6,139 2,940 1,129 31.045 L 20,76 NET INCOME Statements of Comprehensive Income 2002 NET INCOME $ 20,5b7 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 2,225 Minimum Pension Liability (9.773)COMPREHENSIVE INCOME $1 3, ol Statements of Retained Earnings 2002 RETAINED EARNINGS JANUARY 1 $48,833 NET INCOME 20,567 CASH DIVIDENDS DECLARED 21,131 RETAINED EARNINGS DECEMBER 31 See Notes to Financial statements beginning on page L-1.Year Ended December 31, 2001 2000 (in thousands) | |||
$21,565 $20,763 (1,903)Year Ended December 31.2001 (in thousands) | |||
$57,513 21,565 30.245$A&2000$67,110 20,763 30.360 H4 KENTUCKY POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Accrued Tax Benefit Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial statements beginning on page L-1.$ 275,121 373,639 425,817 55,913 165.129 1,295,619 397.304 898.315 6.904 29.871 2,304 22,044 23,802 2,889 (192)10,817 16,127 5,301 1,253 24,320 2,127 110,792 101,976 16.818$1,164,676 S 271,070 374,116 402,537 65,059 15.633 1,128,415 384.104 744.311 6,492 29.477 1,947 20,036 16,012 3,333 (264)12,060 15,766 5,395 33,905 1,314 109,504 97.692 11,572 SL999,048 H-5 KENTUCKY POWER COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock $50 Par value: Authorized 2,000,000 shares outstanding 1,009,000 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareowner S Equity Long-term Debt Long-term Debt Affiliated Companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year -General Long- term Debt Due within one Year -Affiliated Companies Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.S 50,450 208,750 (9,451)48.269 298,018 391,632 60.000 749,650 27. 319 15,000 23,386 46,515 44,035 8,048 6,471 17,803 14. 322 175. 580 178,313 9,165 11.488 13.161$ 50,450 158,750 (1,903)48.833 256,130 176,093 75,000 507. 223 11.929 95,000 66,200 23,464 22,557 4,461 10,305 5,269 38,664 12,882 278,802 168,304 10,405 14,917 7,468 S1,164,676 H-6 KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark-to-Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities | |||
$ 20,567 33,233 9,839 (1,240)2,998 (12,267)(9,426)882 94 44,529 (11,558)(21,491)16.161 72, 321$ 21,565 $ 20,763 32,491 6,293 (1,251)(4,707)(1,454)23,694 (7,658)1,105 (22,942)(1,580)(2,762)(9,446)33, 348 31,034 3,765 (1,252)2,948 (4,376)(20,930)8,386 7,237 39,883 2,025.5,943 62,653 (62. 702)95, 377 INVESTING ACTIVITIES: | |||
construction Expenditures Proceeds From Sales of Property Net Cash Flows Used For Activities Investing (178,700)217 (178,483)(37,206)216 (36 990)(36,209)266 (35.943)FINANCING ACTIVITIES: | |||
capital contributions from Parent Company Issuance of Long-term Debt Retirement of Long-term Debt change in short-term Debt (net)change in Advances From Affiliates (net)Dividends Paid Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 50,000 274,964 (154, 500)(42,814)(21.131)106,519 357 1$947 3-2.3-04 75,000 (60,000)18,564 (30,245)3, 319 (323)2,270$ 1,947 69,685 (105,000)(39,665)47,636 (30 ,360)(57.704)1,730 540-2,270 supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000 and$28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were $22,021, $817,000 and$2,817,000 and in 2002, 2001 and 2000, respectively. | |||
see Notes to Financial Statements beginning on page L-1.H-7 KENTUCKY POWER COMPANY Statements of Capitalization December 31, 2002 2001 (in thousands) | |||
$298.018 $256.130 COMMON SHAREHOLDER S EQUITY LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Senior unsecured Notes Notes Payable Junior Debentures Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 statements beginning on page L-1.352,508 75,000 39,124 (15.000)451.632$7A9,6iQ 59,383 147,625 100,000 39,085 (95.000)251.093 5507.2_2 H-8 KENTUCKY POWER COMPANY Schedule of Lonq-term Debt First mortgage bonds follows: outstanding were as December 31.2002 2001 (in thousands) | |||
% Rate Due 6.65 2003 6.70 2003 6.70 2003 7.90 2023 Unamortized Notes payable to banks outstanding were as follows: December 31.2002 2001 (in thousands) | |||
X Rate Due 7.45 2002 September 20 S -=Junior debentures outstanding were as follows: May 1 June 1 July 1 June 1 Discount S S 15,000 15,000 15,000 14,500 il 17)First mortgage bonds were secured by a first mortgage lien on electric utility plant.Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due 8.72 2025 June 30 unamortized Discount Total 540,000 (876)539,12$40,000 (915)539 08% Rate Due (a) 2002 6.91 2007 6.45 2008 5.50 2007 4.31 2007 4.37 2007 unamortized December 31.2002 2001 (in thousands) | |||
-November 19 S -S 70,000 October 1 48,000 48,000 November 10 30,000 30,000 July 125,000 -November 12 80,400 -December 12 69,564 -Discount (456) (375)S3258S4,Z Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.At December 31, 2002, future annual long-term debt payments are as follows: (a) A floating interest rate is determined monthly. The rate December 31, 2001 was 4.3%.Notes payable to parent company were as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 15,000 60,000 322,964 70.000 467,964 (1.332)S466,-632% Rate Due 4.336 2003 6.501 2006 December 31.2002 2001 (in thousands) | |||
$15,000 S15,000 60.000 60.000 S75,00 57,0 May 15 May 15 H-9 KENTUCKY POWER COMPANY Index to combined Notes to Financial statements The notes to KPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1.Significant Accounting Policies Merger Rate Matters Effects of Regulation Commitments and Contingencies Guarantees Sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 6 Note 7 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 H-10 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 H-I 1 OHIO POWER COMPANY OHIO POWER COMPANY Selected Financial Data 2002 Year Ended December 3 2001 2000 (in thousands) | |||
.INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable To Common stock$2,113,125 1.814,796 298,329 5,376 83. 682 220,023 220,023 1.258$2,098,105 1.857, 395 240,710 18,686 93.603 165,793 (18. 348)147,445 1.258$ 146,187$2,140,331 1.913. 504 226,827 (5,004)119,210 102,613 (18.876)83,737 1.266$ 82,471 1999$1,978,826 1.689.997 288,829 7,000 83.672 212,157 212,157 1,417 LI210,740 1998$2,105,547 1,816.175 289,372 588 80,035 209,925 209,925 1.474 L 20845 2002 December 31, 2001 2000 (in thousands) | |||
-A -A ----BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$5,685,826 2.566.828$5,390,576 2.452 571$5,577,631 2.764.130$2.813 .50 361397.5$5,400,917 2.621.711$2 779,206$4. 675,5 1998$5,257,841 2,461.376$2,796,465 | |||
$4,344,68$4.457.032,93SiIM Common stock and Paid-in Capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common Shareholder's Equity$ 783,684 (72,886)522.316$ 783,684 (196)401.297$ 783,684 398.086 S1A8181Z0$ 783,577 587.424$ 783,536 587. 500 Cumulative Preferred stock: Not subject to Mandatory Redemption | |||
$ 16,648 subject to Mandatory Redemption (a) 8.850 Total Cumulative Preferred stock $ 2549 Long-term Debt (a) $1,067,314 obligations under capital Leases (a) $&65,_626 Total capitalization and Liabilities | |||
$4,457,03$ 16,648 8.850$ 16,648 8.850$ 16,937 8.850$ 17,370 11,850 SZ5__M 25.4982~2~ | |||
S fL8--6&66$6.193,975 t$A__42, 635$4,675,159 (a) Including portion due within one year.1-1 | |||
-OHIO POWER COMPANY Management s Discussion and Analysis of Results of Operations Ohio Power Company (OPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 702,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. | |||
OPCo also sells wholesale power to municipalities and cooperatives. | |||
The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each company's percentage share of AEP Power Pool revenues and costs.Results of Operations Income Before Extraordinary Item increased$54 million or 33% in 2002 mainly due to reductions in operating expenses, predominantly fuel, and interest charges.Income Before Extraordinary Item increased$63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI)program recorded in 2000. In February 2001 the U.S. District Court forthe Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP s consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net Income was also favorably impacted by the growth in and strong performance by the wholesale business. | |||
The effects of the COLI decision in 2000 and favorable wholesale business in 2001 were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the economic downturn.Operating Revenues Operating Revenues increased 1% in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. | |||
Changes in the components of Operating Revenues were: Increase (Decrease) | |||
From Previous Year (Dollars in Millions)2002 2001 Amount % Amount %Retail* $ 11 2 S(66) (8)wholesale Marketing 10 5 (19) (8)unrealized MTM 2 8 33 N.M.Other 1 1 (4) (5)Total wholesale Electricity* | |||
24 2 (56) (5)Energy Delivery* | |||
37 7 85 18 Sales to AEP Affiliates (46) (9) (71) (12)Total SL15 1 VA42) (2)* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 39%. For the fall season, heating degree days increased 32%. This 1-2 reflects a return to more normal weather conditions since 2001 weather was abnormally mild. Sales to AEP Affiliates decreased due to a 15% decrease in price, reflective of lower average fuel cost, while MWH sales rose slightly.Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool. This was the result of an affiliate being able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000.Operating Expenses Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel. Operating Expenses in 2001 also decreased 3%. This reduction was the result of lower Fuel and Income Taxes partially offset by amortization of transition regulatory assets.due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate s two nuclear units returning to service.Wholesale Electricity Purchased Power expense increased in 2002. This was the result of a 11% increase of MWH sales, partially offset by a decrease in price. In 2001 the increase was due to increases in MWH purchases from third parties because of the non-availability of associated nuclear power for resale to wholesale customers and to meet internal demand.AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18%increase of MWH purchased from affiliates with a slight decrease in the average price.The increase for 2001 was also a result of increased purchases through the AEP Power Pool.Changes in the Expenses were: Fuel wholesale Electricity Purchased Power AEP Affiliates Purchased Power Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes Total operating Expenses components of Operating Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Amount % Amount %Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Spom plants, and boiler inspections at the Amos and Cardinal Plants.S C In 2001, the commencement of amortization 102) (15) 5(85) (11) of transition regulatory assets in connection 4 6 is 30 with the transition to customer choice and market-based pricing of retail electricity supply 8 14 12 23 under Ohio deregulation accounted for the 16 4 (4) (1)(6) (4) 18 15 significant increase in Depreciation and 9 4 84 54 Amortization expense.12 SLU4)10 12 (2)(10)(86)(6)(46)(3)The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWH generated. | |||
The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal.Fuel expense decreased 11 % in 2001 mainly The 2002 increase in Taxes Other Than Income Taxes is the result of increases in state excise tax created from a change in the base tax calculation. | |||
The decrease in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax.Income Taxes increased in 2002 due to an increase in both federal and state tax 1-3 | |||
-expenses. | |||
Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis.State taxes increased predominately as a result of the State of Ohio s tax legislation revision involving utility deregulation. | |||
Income Taxes decreased in 2001 due to an unfavorable ruling in AEP s suit against the government over interest deductions claimed relating to AEP s COLI program which was recorded in 2000 and a decrease in pre-tax book income.Nonoperating Income and Nonoperating Expense The major reason for the decrease in Interest Charges in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. | |||
Extraordinary Loss In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. | |||
In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.Nonoperating Expenses decreased during 2002 due to reductions in variable incentive compensation expenses associated with wholesale trading.Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of an increase in the level of trading activity outside of the AEP System s traditional marketing area.The 2002 increase in Nonoperating Income Tax Expense is a result of the favorable tax benefit from the sale of the Ohio Coal companies in 2001. This event also caused the decrease for 2001.Interest Charges The 2002 decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.1-4 OHIO POWER COMPANY Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: Wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (See Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK$1,058,250 589,673 465.202 2,113.125 584,730 67,385 71,154 416,533 136,609 248,557 176,247 113.581 1.814.796 298,329 51,953 28,567 18,010 83.682 220,023 220,023 1.258$ 218,765$1,034,026 552,713 511,366 2.098.105 686, 568 63,441 62,585 400,790 142,878 239,982 159,778 101,373 1.857. 395 240,710 70,108 53,802 (2,380)93.603 165,793 (18.348)147,445 1.258$ 146.187$1,090,297 467,587 582.447 2.140.331 771,969 48,657 50,741 404,410 124,735 155,944 169,527 187.521 1.913.504 226,827 57,163 44,009 18,158 119.210 102,613 (18.876)83,737 1,266 Statements of Comorehensive Income 2002 Year Ended December 31.(in thousands) 2001 023 $147,445 $NET INCOME $2 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability COMPREHENSIVE INCOME 3 The common stock of oPco is wholly owned by AEP.See Notes to Financial statements beginning on page L-1.1-5 220, (542)(72.148)147,333 (196)$147,249 I 2000;83,737 OHIO POWER COMPANY Statement of Retained Earninqs Year Ended December 31.2002 2001 (in thousands) | |||
$398,086 147.445 545.531 2000 Retained Earnings January 1 Net Income$401,297 220,023 621,320$587,424 83,737 671. 161 Deductions: | |||
cash Dividends Declared: Common stock Cumulative Preferred Stock: 4.08% series 4.20% series 4.40% Series 4-1/2% Series 5.90% series 6.02% Series 6.35% series Total Dividends 97,746 58 96 139 439 428 66 32 99,004 142,976 271,813 58 96 139 439 428 66 32 144,234 59 96 139 442 428 66 32 273,075 Retained Earnings December 31 see Notes to Financia7 statements beginning on page L-1.MZJI-6 $AO1,291 $3-9&JO 1-6 OHIO POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES$3,116,825 905,829 1,114,600 260,153 288.419 5,685,826 2. 566.828 3.118.998 61,686 103.230 5,285 95,100 124,244 19,281 (909)87,409 85,379 92,108 12.083 519.980 568.641 84.497 SAA45 t932$3,007,866 891,283 1,081,122 245,232 165,073 5,390,576 2.452.571 2.938.005 62.303 99.706 8,848 84,694 148,563 20,409 (1,379)84,724 88,768 114,280 20,865 569.772 644.625 79.662 4A07 TOTAL ASSETS see Notes to Financial statements beginning on page L-1.1-7 OHIO POWER COMPANY December 31.2002 2001 (in thousands) | |||
CAPITALIZATION AND LIABILITIES CAPITALIZATION: | |||
Common Stock No Par value: Authorized 40,000,000 shares outstanding 27,952,473 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity Cumulative Preferred Stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year -General Long-term Debt Due within one Year Affiliated Companies short-term Debt Affiliated Companies Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued obligations under Capital Leases Energy Trading Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 321,201 462,483 (72,886)522. 316 1,233,114 16,648 8,850 917.649 2. 176.261 227,689 89,665 60,000 275,000 129,979 170,563 145,718 12,969 111,778 18,809 14,360 61,839 80.608 1,171,288 794.387 18.748 39,702 28.957 54,45,032$ 321,201 462,483 (196)401,297 1,184,785 16,648 8,850 1.203,841 2.414.124 130, 386 300,213 131,057 176, 520 5,452 126,770 17,679 16,405 98,081 90.431 962.608 797.889 21.925 50,459 16.682$4,3-9A4-0173 1-8 OHIO POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments for Noncash Items: Depreciation, Depletion and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Extraordinary Loss Mark to Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Customer Deposits Taxes Accrued Disputed Tax and Interest Related to COLI Employee Benefit and other Noncurrent Liabilities Impairment Loss change in other Assets change in other Liabilities Net Cash Flows From Operating Activities | |||
$ 220,023 248,557 46,010 (3,177)(28,693)14,571 704 3,081 8,704 7,517 (14,992)110,298 1,757 (2,233)(133.154)478.973$ 147,445 252,123 215,833 (3,289)18,348 (59,833)51,640 4,852 264 9,887 (34,284)(96,331)(392,026)79,831 (107.704)86.756 S 83,737 200,350 (65,956)(3,399)(56,869)18,876 (5,614)51,430 46,645 45,311 56,069 31,540 60,919 110,494 145,573 (439,448)359.640 639,298 INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds From Sales of Property and other Investment in coal Companies Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt change in Advances From Affiliates (net)Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Decrease in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 (354,797)6,499 (348,298)(170,234)(140,000)275,000 (97,746)(1.258)(134.238)(3,563)8.848$ S5, (344,571)16,778 (32,115)(359.908)300,000 392,699 (297,858)(142,976)(1,258)250,607 (22,545)31. 393 (254,016)6,354 (247,662)74,748 (92,486)(182)(30,663)(194,918)(271,813)(1,262)(516, 576)(124,940)156.333 supplemental Disclosure: | |||
cash paid (received) for interest net of capitalized amounts was $81,041,000, $94,747,000 and$87,120,000 and for income taxes was $105,058,000, $(22,417,000) and $142,710,000 in 2002, 2001 and 2000, respectively. | |||
Noncash acquisitions under capital leases were $106,000,$2,380,000 and $17,005,000 in 2002, 2001 and 2000, respectively. | |||
See Notes to Financia7 Statements beginning on page L-1.1-9 11 OHIO POWER COMPANY Statements of CaDitalization December 31.2002 2001 (in thousands) | |||
$1.233.114 S1.184.785 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 3.762,403$25 par value -authorized shares 4,000,000 call Price shares December 31, Number of shares Redeemed outstanding series 2002 (a) Year Ended December 31. December 31. 2002 2002 2001 2000 Not Subject to Mandatory Redemption-S100 Par: 4.08% $103 ---14,595 4.20% 103.20 --276 22,824 4.40% 104 --432 31,512 4-1/2% 110 --2.181 97.546 subject to Mandatory Redemption-S100 Par (b): 5.90% (c) $ ---6.02% (d) ---6.35% (d) ---1,460 2,282 3,151 9. 755 16. 648 7,250 1, 100 500 8.850 1,460 2,282 3,151 9. 755 16. 648 7,250 1,100 500 8.850 72,500 11,000 5,000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 136,633 141,544 Installment Purchase Contracts 233,340 233,235 senior unsecured Notes 397,341 396,962 Notes Payable to Affiliated company 300,000 300,000 Junior Debentures | |||
-132,100 Less Portion Due within one Year (149.665) | |||
-Long-term Debt Excluding Portion Due within one Year 917,649 1.203.841 TOTAL CAPITALIZATION 52 626 S2,414,14Z (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends.(b) sinking fund provisions require the redemption of 35,000 shares in 2003 and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due dates. shares previously purchased may be applied to the sinking fund requirement. | |||
At the company s optioni all shares are redeemable at S100 per share plus accrued and unpaid dividends with at least 30 days notice beginning on or after November 1, 2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April 1, 2003 for the 6.35% series.(c) commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. shares previously redeemed may be applied to meet sinking fund requirements.(d) Commencing in 2003 and continuing through 2007 sinking fund provisions will require the redemption of 20,000 shares each year of the 6.02% series and 15,000 shares each year of the 6.35% series, in each case at $100 per share. All remaining outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirements. | |||
See Notes to Financial Statements beginning on page L-1.1-10 OHIO POWER COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 6.75 2003 6.55 2003 6.00 2003 6.15 2003 (a) 2022 7.75 2023 7.375 2023 7.10 2023 7.30 2024 Unamortized Total April 1 S 29,850 October 1 27.315 November 1 12,500 December 1 20,000-February 10 -April 1 5,000 October 1 20,250-November 1 12,000 April 1 10,000 Discount (282)1135 633 S 29,850 27,315 12,500 20,000 5,000 5,000 20,250 12,000 10,000 (371)5141, 4A sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands)(a) Redeemed on May 10, 2002.First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 6.75 2004 7.00 2004 6.73 2004 6.24 2008 7-3/8 2038 unamortized Total July 1 $100,000 July 1 75,000 November 1 48,000 December 4 37,225 June 30 140,000 Discount (2.884)S37,4$100,000 75,000 48,000 37,225 140,000 (39263)Notes payable to parent company were as follows:% Rate Due 4.336% 2003 6.501% 2006 Total May 15 May 15 December 31.2002 2001 (in thousainds) | |||
S 60,000 S 60,000 240.000 240.000 Sa_,0 outstanding were as December 31.2002 2001 (in thousands) | |||
Junior debentures follows:% Rate Due Mason County, West Virginia: 5.45% 2016 December Marshall county, West Virginia: 5.45% 2014 July 1 5.90% 2022 April 1 6.85% 2022 June 1 Ohio Air Quality Development 5.15% 2026 May 1 unamortized Discount Total December 31.2002 2001 (in thousands) | |||
I S 50,000 S 50,000 50,000 50,000 35,000 35,000 50,000 50,000% Rate Due (a) 2025 (a) 2027 unamortized Total September 30 S -S 85,000 March 31 -50,000 Discount -(2.900)1 -si (a) Redeemed on July 24, 2002 At December 31, 2002 future annual long-term debt payments are as follows: 50,000 (1.660)12I33,34 50,000 (1.765)Under the terms of the installment purchase contracts, OPCo is required to pay amounts 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 149,665 223,000 240,000 459.475 1,072,140 4 826 1-11 OHIO POWER COMPANY Index to combined Notes to Financial statements The notes to OPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans Business segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 1-12 INDEPENDENT AUDITORS'REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying balance sheets and statements of capitalization of Ohio Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Ohio Power Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.1s1 Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 1-13 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income Preferred stock Dividend Requirements Gain on Reacquired Preferred stock Earnings Applicable to Common stock$ 793,647 708.926 84,721 (3,239)40.422 41,060 213$957,000 860.012 96,988 20 39.249 57,759 213$956,398 859.729 96,669 8,974 38,980 66,663$749,390 650.677 98,713 946 38.151 61,508 212$780,159 665.085 115,074 (91)38.074 76,909 212 213 1$ 40.848 LiZJ_.~ 1_0,A5I1 S-512% 9 6 $76-, 2002 December 31.2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$2,759,504 1.239,855$i,519,649 | |||
$1,76,69$2,695,099 1.184.443$1,510,656 | |||
$2,604,670 1.150.253$1.,454,417 | |||
$2,459,705 1,114.255$1 , 3A5,45Q 24$2,391,722 1.082.081 Total Assets$IAZ10 Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity$ 337,246 (54,473)116.474 S 399,247$ 337,246 142.994$ 480s2A0$ 337,246 137,688$ 474,934$ 337,246 139.237 S 476,483 S 337,246 142. 941 cumulative Preferred Stock: Not subject to Mandatory Redemption Preferred securities of subsidiary Trust Long-term Debt (a)$ 5. 27$LJ575000 S 75QQ0$ 545,437$ 451,129$_384,064 Total capitalization and Liabilities$1,748,911 | |||
$1.I 524, 846 S1,471,09 (a) Including portion due within one year.J-1 L. i PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Management s Narrative Analysis of Results of Operations Public Service Company of Oklahoma (PSO)is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma. | |||
PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. | |||
Wholesale power marketing activities are conducted on PSO s behalf byAEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
Results of Operations In 2002, Net Income decreased by $17 million or 29% primarily resulting from reduced wholesale margins and increased depreciation expense.Changes in Operating Expenses Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount %S(215.3) (47)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 23.3 45.7 (4.1)1.9 96 104 (3)4 5.6 7 2.1 (10.3)S(514)7 (30)(18)N.M. = Not Meaningful The decrease in Fuel expense in 2002 was primarily due to lower market prices for natural gas and fuel oil, and deferral of underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and to the amortization of previously overrecovered fuel costs.Changes in Operating Revenues Operating revenues decreased in 2002 as a result of reduced wholesale margins, a decline in fuel recovery revenue and decreases due to the interchange cost reconstruction (ICR) adjustments (see Note 6).Increase (Decrease) | |||
From Previous Year (dollars in millions)Amount %wholesale Electricity* | |||
S(149.7) (23)Energy Delivery* | |||
13.6 5 sales to AEP Affiliates t27.3) (74)Total operating Revenues S(163) (17)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.The increase in Electricity Marketing Purchased Power expense in 2002 resulted mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices.The increase in the AEP Affiliates Purchased Power expense in 2002 resulted mainly from the ICR adjustments (see Note 6).Other Operation expense decreased in 2002 primarily due to lower transmission expenses and decreased factoring expenses due to reduced revenues.Maintenance expense increased, in 2002 largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002.Depreciation and Amortization expense increased in 2002 primarily due to the additional depreciable capitalized costs involved in repowering NortheastStation Units 1 & 2 completed in 2001.Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in ad valorem taxes.J-2 Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.Other Changes Nonoperating Expenses increased primarily due to the write-down of certain non-utility investments in 2002.J-3 | |||
--t PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Income Year Ended December 31.2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES$508,661 275,547 9,439 793,647 246,199 47,507 89,454 133,538 48,060 85,896 34,077 24.195 708.926 84,721 1,920 6,971 (1,812)40.422 ZO21 (in thousands) | |||
$658,352 261,877 36.771 957.000 461,470 24,187 43,758 137,678 46,188 80,245 31,973 34,513 860.012 96,988 2,112 1,740 352 39.249 2000$696,626 245,124 14, 64 8 956. 398 402,933 88,088 60,788 121,697 45,858 76,418 28,688 35,259 859.729 96,669 8,807 1,139 (1,306)38.980 NET INCOME GAIN ON REACQUIRED PREFERRED STOCK LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 41,060 1 213 57,759 213 ,$L5 66,663 212$ 66A S5$ 40,848 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 2000 (in thousands) | |||
$ 41,060 $57,759 $66,663 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(42)(54.431)$ (13.413)$5ZL75-9 I The common stock of P50 is owned by a wholly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-4 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Retained Eaminqs Year Ended December 31, 2002 2001 (in thousands) | |||
$137,688 57,759 2000$139,237 66,663 BEGINNING OF PERIOD NET INCOME DEDUCTIONS: | |||
capital Stock Gains Cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$142,994 41,060 (1)67,368 213$116,474 52,240 213 68,000 212$142,994 1IaL&6 The common stock of P50 is owned by a who ly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-5 It i -PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$1,040,520 432,846 990,947 206,747 88.444 2,759,504 1.239.855 1.519.649 OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: | |||
Customers Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS 4.481 16,774 31,687 14,139 (84)19,973 37,375 76,470 3,841 2.735 202.910$1,034,711 427,110 972,806 203,572 56.900 2,695,099 1,184.443 1,510,656 41.020 21. 354 5,795 31,144 10,905 (44)21,559 36,785 756 26,259 2.368 135. 527 REGULATORY ASSETS 26. 150 DEFERRED CHARGES 18.117 TOTAL ASSETS$1. 748. 911 See Notes to Financial statements beginning on page L-1.J-6 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CAPTTALIZATION AND LIARILTTIFS December 31, 2002 2001 (in thousands) | |||
CAPITALIZATION: | |||
Common Stock $15 Par value: Authorized shares: 11,000,000 Issued Shares: 10,482,000 outstanding Shares: 9,013,000 Paid-in capital Accumulated Other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred stock Not subject to Mandatory Redemption Pso-obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Over-Recovered Fuel Costs Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS REGULATORY LIABILITIES AND DEFERRED CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.S 157,230 180,016 (54,473)116,474 399. 247$ 157,230 180,016 142.994 480.240 5,267 5,267 75,000 445.437 924.951 54.761 100,000 86,105 61,169 78,076 21,789 6,854 6,979 3,260 24. 957 389.189 341.396 32.201 32.611 1,581$1,776,690 75,000 345.129 905.636 7,263 106,000 123,087 72,759 40,857 21,041 9,476 18,150 7,298 31,718 12,216 442.602 296.877 33,992 49.080 13.461$1. 748, 911.J-7 | |||
--PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments to Reconcile Net Income to Net Cash from operating Activities: | |||
Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits changes in Certain Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies other Property and Investments Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement changes in Other Assets changes in Other Liabilities Net Cash From Operating Activities | |||
$ 41,060 85,896 75,659 (1,791)(3,737)996 (419)25,629 (11,296)(85,190)2,215 (6,928)122.094$ 57,759 80,245 (17,751)(1,791)21,405 (589)(2,809)(55,319)16,491 51,987 (9,120)9.351 149,859 S 66,663 76,418 25,453 (1,791)(28,826)677 7,994 89,330 (16,821)(36,798)(15,063)4,482 65.6193 165.615 INVESTING ACTIVITIES: | |||
Construction Expenditures Proceeds from Sale of Property other Items Net cash used For Investing Activities 963 (88.402)FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on cumulative Preferred stock Net cash From (used For)Financing Activities 187,850 (106,000)(36,982)(67,368)(213)(22,713)(124,520)(359)(124,879)(20,000)41,967 (52,240)(213)(30, 486)(176,851)(176.851)105,625 (20,000)1,951 (68,000)(212)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 10,979 5.795$1 6977 (5,506)11.301 8,128 3 .173 SL==I~i supplemental Disclosure: | |||
Cash paid (received) for interest net of capitalized amounts was $38,620,000, $38,250,000 and$33,732,000 and for income taxes was ($38,943,000), $38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively. | |||
See Notes to Financial statements beginning on page L-1.J-8 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
$ 399.247 $480.240 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: Cumulative | |||
$100 par value authorized redeemable at the option of PSO upon 30 days notice.Call Price December 31, Number of shares Redeemed Series 2002 Year Ended December 31, 2002 2001 2000 Not subject to Mandatory Redemption: | |||
4.00% $105.75 6 -25 4.24% 103.19 ---TRUST PREFERRED SECURITIES PSo-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of PSO, 8.00%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Less Portion Due Within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION see Notes to Financial Statements beginning on page L-1.shares 700,000, Shares outstanding December 31. 2002 44,600 8,069 4,460 807 5.267 75.000 298,079 47,358 200,000 (100.000)445.437 4,460 807 5. 267 75.000 297,772 47,357 106,000 (106. 000)345.129 J-9 | |||
--PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Lona-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due 6.25 2003 7.25 2003 7.38 2004 6.50 2005 7.38 2023 unamortized April 1 July 1 December 1 June 1 April 1 Discount S 35,000 65,000 50,000 50,000 100,000 (1.921)S29Bs29 S 35.000 65,000 50,000 50,000 100, 000 (2 228)Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) | |||
% Rate Due (a)i 2002 (b) 2032 TOTAL December 31.2002 2001 (in thousands) | |||
November 21 S -S106,000 December 31 200 000 -520 00M 16 0 (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was $2.775%.(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) | |||
Rat Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 -December 1 S 1,000 S 1,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total$100,000 50,000 50,000 1,000 346. 360 547, 360 (1.923)545 437 Oklahoma Development Finance Authority (ODFA): 4.875 2014 -June 1 Red River Authority of Texas: 6.00 2020 June 1 Unamortized Discount Total i 33,700 33,700 12,660 12,660 (2) (3),Al 3-58 547 357 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of PSO.J-1 0 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Index to Combined Notes to Consolidated Financial Statements The notes to PSO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to P50. The combined footnotes begin on page L-1.combined Footnote Reference significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Benefit Plans Note 14 Business segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric utility Plant Note 28 Related Party Transactions Note 29 J-1 1 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiary as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 J-12 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements LOSS on Reacquired Preferred stock Earnings Applicable to Common stock$1,084,720 942.251 142,469 (309)59,168 82,992 82,992 229 Year En 2001$1,101,326 955,119 146,207 741 57, 581 ided December 31, 2000 (in thousands) | |||
$1,118,274 | |||
$989.996 128,278 3,851 59,457 _1999 971,527 824,465 147,062 (1,965)58,892 86,205 (3,011)83,194 229----1998$ 952,952 802,274 150,678 2,451 5,9135 97,994 97,994 705 89,367 72,672 89,367 72,672 229 229$ 8J39& U$ 72,443_$ --- a33 December 31, 2002 2001 2000 (in thousands) 1999 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$3,596,174 | |||
: 1. 697. 338$2 2S L67I5$ 380,663 (53,683)334,789$3,460,764 | |||
$3,319,024 | |||
$3,231,431 1,550,618 1,457,005-$i Q0,146 $1&862019$L380,616 | |||
$ 380,663$ 380,663 $ 380,663 1.384.242 ,2 16762:$ 380,663 283, 546 1998$3,157,911 1.317.057-£2 IQ -85A'25$ 380,663 296, 581$_677L244 308,915 293,989 S$_&6W5i8 | |||
$-6!A.-5i2 S-664,ZO0.11 1 LQ1 $ 4,70-1~ 2QTrust Preferred securities Long-term Debt (a)Total capitalization and Liabilities | |||
$__11O0,Q | |||
$ 110,000 A11 4 QQ00£_lUXlQQQ_$__M-t645 S& 6A45,963 A15&£$Z2 0-8,M~z$2,3Q0,676 | |||
$ 2 58 3&5102 6,162$2 Q8Z,258 (a) Including portion due within one year.K-1 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas. | |||
SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. | |||
Wholesale power marketing activities are conducted on SWEPCo s behalf by AEPSC.SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. | |||
Results of Operations In 2002, Net Income decreased | |||
$6.4 million or 7% primarily resulting from reduced margins.In 2001, Net Income increased | |||
$16.7 million or 23% resulting primarily from the favorable impact of our sharing in AEP s power marketing activities for a full year.Changes in Operating Revenues Operating Revenues decreased 2% for 2002 primarily due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation | |||
($12.6 million) and the positive impact of the interchange cost reconstruction (ICR) adjustments (see Note 6).In 2001, Operating Revenues decreased | |||
$17 million or 2% resulting from unfavorable wholesale marketing and trading conditions. | |||
Changes in Operating Expenses Increase (Decrease) | |||
From Previous Year (dollars in millions)2002 2001 Amount % Amount X S(69) (15) S(41) (8)26 143 (40) (69)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 26 165 18 10 (8) (10)2 19 12 7-(1)3 3 15 14 (1)(8)(1)(20)(1)2 16£LI)4 60 (4)Increase (Decrease) | |||
From Previous Year (dollars in millions 2002 2001 Amount % Amount %wholesale Electricity* | |||
$(25) (4) S(21) (3)Energy Delivery* | |||
15 5 (12) (3)Sales to AEP Affiliates | |||
.7) (9) 16 26 Total operating Revenues £-1Z) (2) ILU) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Fuel expense decreased in 2002 due to a reduction in MWH generated and a decrease in the cost of fuel, primarily natural gas.Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. | |||
K-2 L.In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was mainly due to reduced prices caused by decreased electricity demand.The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in 2002 by$4.3 million. Other Operation expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other Operation expense increased also as a result of the Dolet Hills mining operation in June 2001.The 10% decrease in Maintenance expense in 2002 is primarily a result of higher storm and tree trimming related expenses in 2001.The increase in Depreciation and Amortization expense in 2002 is primarily due to the addition of Dolet Hills in June 2001, which added $3.0 million of additional expense in 2002. Depreciation and Amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. | |||
In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income. In 2001, the increase in income tax expense was primarily due to an increase in pre-tax income.K-3 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES$ 664,185 348,236 72,299 1.084,720 388,334 44,119 42,022 189,024 66,855 122,969 55,232 33,696 942.251$ 689,085 333,004 79,237 1.101.326 457,613 18,164 15,858 171,314 74,677 119,543 55,834 42,116 955.119$ 710,200 344,950 63,124 1.118.274 498,805 58,518 13,338 159,459 75,123 104,679 53,830 26,244 989, 996 OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 NONOPERATING EXPENSES 1,797 4,512 3,229 542 5,487 3,112 (1,476)NONOPERATING INCOME TAX EXPENSE (CREDIT)1,772 INTEREST CHARGES 59.168 57, 581 59.457 NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 229 S 82.e763 229 S 89,138 229 S 72.443 Consolidated Statements of Comprehensive Income 2002 Year Ended December 31.2001 2000 (in thousands) | |||
--- ---NET INCOME $82,992 $89,36 OTHER COMPREHENSIVE INCOME (LOSS): cash Flow Power Hedges (48) -Minimum Pension Liability (53.635) -COMPREHENSIVE INCOME "24.309 S___36 The common stock of SWEPco is owned by a who77y owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.7$72,672$72 f92 K-4 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31, 2002 2001 2000 (in thousands) | |||
BALANCE AT BEGINNING OF PERIOD NET INCOME$308,915 82,992 DEDUCTIONS: | |||
cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$293,989 $283,546 89,367 72,672 74,212 62,000 229 229$ 3C&4915 $s91I9&9 56,889 229 The common stock of SwEPCo is owned by a wholly owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.K-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) | |||
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and cash Equivalents Accounts Receivable: | |||
Customers Affiliated Companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financia7 statements beginning on page L-1.$1,503,722 575,003 1,063,564 378,130 75,755 3,596,174 1.697. 338 1.898.836 5,978 5,119 2,069 62,359 19,253 (2,128)61,741 33,539 2,865 4,388 17,851 201.937 49,233 47. 572$2,20,65$1,429,356 538,749 1,042,523 376,016 74.120 3,460,764 1.550.618 1.910,146 43.000 24,508 5,415 43,133 12,069 (89)52,212 32,527 8,839 30,139 18,716 202.961 52. 308 67, 753$2,300,676 K-6 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CAPITALIZATION AND LIABILITIES December 31.2002 2001 (in thousands) | |||
CAPITALIZATION: | |||
Common stock $18 Par value: Authorized 7,600,000 Shares Outstanding 7,536,640 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo Long-term Debt TOTAL CAPITALIZATION | |||
$ 135,660 245,003 (53,683)334,789 661,769 4,701 110,000 637.853 1.414.323 78.494$ 135,660 245,003 308.915 689,578 4,701 110,000 494,688 1. 298.967 40,109 OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: | |||
Long-term Debt Due within One Year Advances from Affiliates, net Accounts Payable General Accounts Payable Affiliated Comp;Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Cont over-recovered Fuel other TOTAL CURRENT LIABILITIES ani es 55,595 23,239 62,139 58,773 20,110 19,081 17,051 3,724 17,226 34, 565 311.503 racts 150, 595 117,367 71,810 37,469 19,880 36,522 13,027 36,297 5,487 26,074 514.,528 369.78 48.714 13.,127 15,45S0 DEFERRED INCOME TAXES 341.064 DEFERRED INVESTMENT TAX CREDITS 44,190 REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 1.806 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$2,208,675 2LINJ7U K-7 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) | |||
OPERATING ACTIVITIES: | |||
Net Income Adjustments to Reconcile Net Income to Net cash Flows From Operating Activities: | |||
Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts Changes in Certain Current Assets and Liabilities: | |||
Accounts Receivable (net)Fuel, Materials and supplies Accounts Payable Taxes Accrued Transmission coordination Agreement Settlement Fuel Recovery change in other Assets change in other Liabilities Net cash Flows From Operating Activities | |||
$ 82,992 122,969 (3,134)(4,524)$ 89,367 119,543 (31,396)(4,453)(1,151) (10,695)(24,371)(10,541)11,633 (17,441)17,713 24,257 12.16 210.563 (11,447)(19,578)(34,489)25,298 34,423 1,323 11, 714 169.610 S 72,672 104,679 14,653 (4,482)7,795 (1,254)22,103 43,962 (13,150)(24,406)(38,357)54,414 (37.001)201.628 INVESTING ACTIVITIES: | |||
Construction Expenditures Purchase of Dolet Hills Mining operations other Net cash Flows used For-Investing Activities (111,775)1.134 (110.641)FINANCING ACTIVITIES: | |||
Issuance of Long-term Debt Redemption of Preferred stock Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents Cash and Cash Equivalents January 1 cash and cash Equivalents December 31 198,573 (150,595)(94,128)(56,889)(229)(103,268)(3,346)5.415 (111,725)(85,716)(411)(197.852)(595)106,786 (74,212)(229)31.750 3,508 1.907 (120,671)446 (120.225)149,360 (1)(45,595)(124,074)(62,000)(229)(82.5 39)(1,136)3.043 Supplemental Disclosure: | |||
Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000 and$51,111,000 and for income taxes was $60,451,000, $49,901,000 and $27,994,000 in 2002, 2001, and 2000, respectively. | |||
See Notes to Financia7 statements beginning on page L-1.K-8 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) | |||
S 661.769 $ 689.578 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 1,860,000 call Price December 31, Number of shares Redeemed series 2002 Year Ended December 31E 2002 2001 2000 Not subject to Mandatory Redemption: | |||
4.28% $103.90 ---4.65% $102.75 ---5.00% $109.00 --12 Shares Outstanding December 31. 2002 7,386 1,907 37,715 TRUST PREFERRED SECURITIES SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of SWEPCo, 7.875%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financial statements beginning on page L-1.740 190 3.771 4.701 110.000 315,420 179,183 198,845 (55.595)637. 853 11_41Mv23 740 190 3. 771 110.000 315,449 179,834S 150,000 (150. 595)494.688 K-9 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due 6-5/8 2003 7-3/4 2004 6.20 2006 6.20 2006 7.00 2007 7-1/4 2023 6-7/8 2025 unamortized February 1 June 1 November 1 November 1 Se tember Juqy 1 October 1 Discount S 55,000 40,000 5, 505 1,000 I 90,000 45,000 80 000 (1.085)S315-420 S 55,000 40,000 5,650 1,000 90,000 45,000 80,000 (1.201)Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. | |||
% Rate Due 4.50 2005 July 1 (a) 2002 March 1 Unamortized Discount December 31, 2002 2001 Otiw thousandcs-) | |||
S200,000 S --150,000_. 198;85 5) 0OO (a)A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.311%.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2002 2001 (in thousands) | |||
% Rate Due DeSoto County: At December 31, 2002 future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) | |||
S 55,595 52,885 200,595 6,520 90,450 287.695 693,740 (292)S69344 7.60 2019 January 1 S 53,500 Sabine:$ 53,500 6.10 2018 April 1 Titus County: 6.90 2004 -November 1 6.00 2008 -January 1 8.20 2011 August 1 81,700 81,700 See Note 25 for discussion of Trust Preferred Securities issued by a wholly-owned statutory business trust of SWEPCo.12,290 12,290 12,620 13,070 17,125 17,125 Unamortized Premium SIZR-183 S 179-,3A K-10 i-SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to SWEPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. | |||
Listed below are the combined notes that apply to SWEPCo.The combined footnotes begin on page L-1.Significant Accounting Policies Extraordinary Items and Cumulative Effect Goodwill and other Intangible Assets Merger Rate Matters Effects of Regulation Customer choice and Industry Restructuring commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and Sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 K-1I INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. | |||
Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. | |||
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. | |||
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. | |||
We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generallyaccepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 K-12 COMBINED NOTES TO FINANCIAL STATEMENTS Index to Combined Notes to Financial Statements The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. | |||
The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 2. Extraordinary Items and Cumulative Effect AEP, APCo, CSPCo, OPCo, SWEPCo, TCC, TNC 3. Goodwill and Other Intangible Assets AEP, SWEPCo 4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC, TNC 5. Nuclear Plant Restart AEP, I&M 6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC 7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 8. Customer Choice and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo, TCC, TNC 9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 11. Sustained Earnings Improvement Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 12. Acquisitions, Dispositions and Discontinued AEP, OPCo, SWEPCo, TCC, TNC Operations | |||
: 13. Asset Impairments and Investment Value AEP, APCo, CSPCo, I&M, KPCo, OPCo, TCC, TNC Losses 14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 15. Stock-Based Compensation AEP 16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 17. Risk Management, Financial Instruments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo and Derivatives PSO, SWEPCo, TCC, TNC L-1 | |||
: 18. Income Taxes 19. Basic and Diluted Earnings Per Share 20. Supplementary Information | |||
: 21. Power and Distribution Projects 22. Leases 23. Lines of Credit and Sale of Receivables | |||
: 24. Unaudited Quarterly Financial Information | |||
: 25. Trust Preferred Securities | |||
: 26. Minority Interest in Finance Subsidiary | |||
: 27. Equity Units 28. Jointly Owned Electric Utility Plant 29. Related Party Transactions | |||
: 30. Subsequent Events (Unaudited) | |||
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP AEP, APCo, CSPCo, I&M, OPCo AEP AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, PSO, SWEPCo, TCC AEP AEP* CSPCo, PSO, SWEPCo, TCC, TNC AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP L-2 | |||
: 1. Significant Accounting Policies: Business Operations AEP s (the Company s)principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP s eleven domestic electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC, are SEC registrants. | |||
AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. | |||
These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. | |||
AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent, other commodities in the United States and Europe. In addition,theCompanysdomestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.International operations include supply of electricity and other non-regulated power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. | |||
We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale.The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. | |||
See Note 13 for further discussion of changes in our communications related business and other business operations announced in 2002.Rate Regulation AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. | |||
The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated bythe authorities of that country and are generally subject to price controls.Principles of Consolidation AEP s consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially controlled subsidiaries. | |||
The consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC include the registrant and its wholly-owned subsidiaries. | |||
Significant intercompany items are eliminated in consolidation. | |||
Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income forAEP and nonoperating income for the registrant subsidiaries. | |||
Basis of Accounting | |||
-As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. | |||
In accordance with SFAS 71,"Accounting for the Effects of Certain Types of Regulation, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. | |||
Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia byAPCo in June 2000, in Texas byTCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8, "Customer Choice and Industry Restructuring for additional information. | |||
Use of Estimates | |||
-The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. | |||
Actual results could differ from those estimates. | |||
L-3 Property, Plant and Equipment Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. | |||
Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. | |||
Additions, major replacements and betterments are added to the plant accounts. | |||
For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. | |||
The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses. | |||
Plants are tested for impairment as required under SFAS 144. See Note 13.Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization -AFUDC is a noncash, nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. | |||
The amounts of AFUDC for 2002, 2001 and 2000 were not significant. | |||
Effective with the discontinuance of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia, West Virginia and other non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized were not material in 2002, 2001, and 2000.Depreciation, Depletion and Amortization | |||
-Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, otherthan coal-mining property, and is calculated largely through the use of composite rates by functional class as follows: Functional Class of ProDertv Production: | |||
Steam-Nuclear Steam-Fossil -Fi red Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: | |||
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: | |||
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Annual Composite Depreciation Rates Ranges 2002 2.5% to 3.4%2.6% to 4.5%1.9% to 3.4%1.7% to 3.0%3.3% to 4.2%1.8% to 9.9%Annual Composite Depreciation Rates Ranges 2001 2.5% to 3.4%2.5% to 4.5%1.9% to 3.4%1.7% to 3.1%2.7% to 4.2%1.8% to 15.0%Annual Composite Depreciation Rates Ranges 2000 2.8% to 3.4%2.3% to 4.5%1.9% to 3.4%1.7% to 3.1%3.3% to 4.2%2.5% to 7.3%L4 The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which were as follows: Nuclear Steam Hyd ro Transmission Distribution General AEGCo APCo CSPco I&M KPCo OPCo PSO SWEPCo TCC TNC 3.4 2.5 3.5%3.4 3.2 4.5 3.8 3.4 2.7 3.4 2.6 2.8 2.9 3.4 2. 7 1.9 2.2 2.3 1.9 1.7 2.3 2.3 2.7 2.3 3.1 3.3 3.6 4.2 3.5 4.0 3.4 3.6 3.5 3.3 2.8%3.1 3.2 3.8 2.5 2.7 6.3 4.7 4.0 6.8 Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. | |||
The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages. | |||
These costs are included in the cost of coal charged to fuel expense for coal used by utility operations. | |||
Current average amortization rates are $0.32 per ton in 2002,$3.46 per ton in 2001 and $5.07 per ton in 2000.In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia. | |||
See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in 2002.Cash and Cash Equivalents | |||
-Cash and cash equivalents include temporary cash investments with original maturities of three months or less.Inventory Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. | |||
For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market.Materials and supplies inventories are carried at average cost.Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be carried atfairvalue until December31,2002, and inventory purchased from October 26 through December 31, 2002 was carried at the lower of cost or market. Effective January 1, 2003, all natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held in connection with trading operations by approximately | |||
$39 million. This change will be accounted for as a cumulative effect of a change in accounting principle. | |||
Accounts Receivable AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for certain non-affiliated utilities. | |||
On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreementwith a group of banks and commercial paper conduits. | |||
This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the companys balance sheet. See Note 23 for further details.Foreign Currency Translation | |||
-The financial statements of subsidiaries outside the U.S. which are included in AEP s consolidated financial statements are measured using the local currency as the functional currency and translated into U.S.dollars in accordance with SFAS 52 "Foreign Currency Translation | |||
.Assets and liabilities are L-5 translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on AEP s Consolidated Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual currency transaction gains and losses are recorded in income.Deferred Fuel Costs -The cost of fuel consumed is charged to expense when the fuel is burned.Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulators review and approval. | |||
The amount of deferred fuel costs under fuel clauses forAEP was $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "Effects of Regulation | |||
.We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. | |||
In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings. | |||
This is also true for certain of AEP s Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 6, "Rate Matters and Note 8,"Customer Choice and Industry Restructuring for further information about fuel recovery.Revenue Recognition | |||
-Regulatory Accountinq | |||
-The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. | |||
In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds)are recorded to reflect the economic effects of regulation by matching expenses with their recoverythrough regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period.Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made.When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. | |||
If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.Traditional Electricity Supply and Deliverv Activities | |||
-Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. | |||
Transportation and L-6 storage revenues also include the accrual of earned, but unbilled andlor not yet metered gas.Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133.Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves.Energy Marketinq and Trading Transactions In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). | |||
Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps.We use the mark-to-market method of accounting for trading activities as required by EITF Issue No.98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. | |||
For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net in revenues as unrealized gains and losses from mark-to-marketvaluations. | |||
When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. | |||
In October 2002, management announced plans to focus on wholesale markets around owned assets.All of the registrant subsidiaries except AEGCo participate in AEP s wholesale marketing and trading of electricity. | |||
For l&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash.Where this amount is recorded on the income statement depends on whether the contract s delivery points are within or outside of AEP s traditional marketing area. For contracts with delivery points in AEP s traditional marketing area, the total gain or loss realized in cash for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). | |||
For contracts with delivery points outside of AEP s traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income.Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. | |||
For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP s traditional marketing area or not determines where the contract is reported in the income statement. | |||
Physical forward trading sale and purchase contracts with delivery points in AEP s traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP s traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis.The trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in AEP s revenues until the contracts settle. When these contracts settle, the net proceeds are recorded in revenues and reverse the prior cumulative unrealized net gain or loss.APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized L-7 gains and losses, as well as the net proceeds upon settlement, in nonoperating income.The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked-to-market based mainly on AEP-developed valuation models. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Such valuation adjustments provide for a better approximation of fair value. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with AEP-developed price models.As explained above, the effect on AEP s Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP s regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. | |||
Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate. | |||
Construction Projects for Outside Parties Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. | |||
This method recognizes revenue in proportion to costs incurred compared to total estimated costs.Debt InstrumentHedging and RelatedActivities In order to mitigate the risks of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges.There were no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17 'Risk Management, Financial Instruments and Derivatives for further discussion of the accounting for risk management transactions. | |||
Levelization of Nuclear Refueling Outage Costs -In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M s Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and 'ending with the beginning of the next outage.Maintenance Costs Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.See below for an explanation of costs deferred in connection with an extended outage at l&M s Cook Plant.Amortization of Cook Plant Deferred Restart Costs -Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized | |||
$40 million each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and l&M.Other Income and Other Expenses Other Income includes non-operational revenue including area business development and river transportation, equity earnings of non-consolidated subsidiaries, gains on dispositions of L-8 property, interest and dividends, an allowance for equity funds used during construction (explained above) and miscellaneous income. Other Expenses includes non-operational expense including area business development and river transportation, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses.AEP Consolidated other Income and Deductions amortized over the life of the regulated plant investment. | |||
Excise Taxes AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. | |||
These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement. | |||
December 31, 2002 2001 2000 (in millions)OTHER INCOME: Equity Earnings Non-operational Revenue Interest and Miscellaneous Income Gain on sale of Frontera Gain on sale of Retail Electric Provider Total other Income OTHER EXPENSES: Property Taxes and Miscellaneous Expenses Non-operational Expenses Fiber optic and Datapult Exit Costs Provision for Loss -Airplane Total other Expenses S 104 S 123 187 123$ 22 71 Debt and Preferred Stock Gains and losses 25 16 2 from the reacquisition of debt used to finance-73 -domestic regulated electric utility plant are 129 --generally deferred and amortized over the S 45 S- ___ remaining term of the reacquired debt in accordance with their rate-making treatment. | |||
If debt associated with the regulated business is S 142 S 68 5 28 refinanced, the reacquisition costs attributable to 179 56 49 the portions of the business that are subject to-49 -cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the-14 term of the replacement debt commensurate with S1321 s1&z L z their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to EP System follows the SFAS 71 are reported as a Loss on Reacquired ting for income taxes as Debt, an extraordinary item on the Consolidated lAccounting for Income Statements of Operations of AEP and TCC. See iility method, deferred discussion of SFAS 145 in New Accounting | |||
'ded for all temporary Pronouncements section of this note for new book cost and tax basis treatment effective in 2003.Income Taxes -The AE liability method of accoun prescribed by SFAS 109, Taxes. Under the liat income taxes are provi differences between the I of assets and liabilities which will result in a future tax consequence. | |||
Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense.Investment Tax Credits -Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is included in interest charges.Where rates are regulated, redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistentwith the timing of its inclusion in rates in accordance with SFAS 71.L-9 Goodwill and Intangible Assets In June 2001, the FASB issued SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo.SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30,2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. | |||
We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note 3 for further discussion of our components of goodwill and intangible assets.SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually. | |||
SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1,2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. | |||
The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142.In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002.Nuclear Trust Funds Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. | |||
By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers funds and to allow those funds to earn a reasonable return. In general, limitations include:.Acceptable investments (rated investment grade or above)* Maximum percentage invested in a specific type of investment | |||
* Prohibition of investment in obligations of the applicable company or its affiliates. | |||
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. | |||
The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. | |||
Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115,"Accounting for Certain Investments in Debt and Equity Securities. | |||
Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liabilityaccount forthe nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.Comprehensive Income (Loss) -Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other, events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by L-1 0 | |||
-owners and distributions to owners.Comprehensive income (loss) has two components: | |||
net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.Components of Other Comprehensive Income (Loss) Other comprehensive income (loss) is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income (Loss) for AEP.segment as viewed by the chief operating decision-maker. | |||
See Note 16, "Business Segments for further discussion and details regarding segments.Common Stock Options At December 31, 2002, AEP has two stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 15. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. | |||
No stock-based employee compensation expense is reflected in AEP s earnings, as all options granted under these plans had exercise prices equal to or above the marketvalue of the underlying common stock on the date of grant. The following table illustrates the effect on AEP s net income (loss)and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation , to stock-based employee compensation. | |||
Foreign Currency Adjustments unrealized Losses on Securities unrealized Gain on Hedged Derivatives Minimum Pension Liability December 31, 2002 2001 2000 (in millions)S 4 S(113) S (99)(2) --(16) (3) -(595) (c ) (4)Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of December 31, 2002 and 2001 is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the year ended December 31, 2000 was zero.Year Ended December 31, 2002 2001 2000 (in millions except per share data)$ (519) S 971 $ 267 components December 31, 2002 2001 (in thousands) | |||
Net Income(Loss), as reported Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro forma net income (loss)Earnings (Loss) per share: Basic as reported Basic pro forma Diluted as reported Diluted pro forma L__)5Th57) 5.3 0 (12)S-95 LZ34 cash Flow Hedges: APCO cSPco I&M KPCo oPco PSO SWEPCo TCC TNC Minimum Pension Liability: | |||
APCO cSPco INM KPCO oPco PSO SWEPCo TCC TNC S(1,920)(267)(286)322 (738)(42)(48)(36)(15)S (340)(3,835)(1,903)(196)S-UI5) S2Z97 SO. S3_____) SIZAZg OM18 S(70,162)(59,090)(40,201)(9,773)(72,148)(54,431)(53,635)(73,124)(30,748)Earnings Per Share (EPS) AEP calculates earnings (loss) per share in accordance with SFAS No. 128, "Earnings Per Share (see Note 19). Basic earnings (loss) per common share is calculated bydividing neteamings (loss) available to common shareholders by the weighted average number of common shares outstanding during the'-period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming Segment Reporting The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business L-1 I conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. | |||
Basic and diluted EPS are the same in 2002, 2001 and 2000.AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS.Reclassification Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. | |||
This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts and Emerging Issues Task Force Topic D-43,"Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.39 .Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy.Certain additional prior year financial statement items have been reclassified to conform to current year presentation. | |||
Such reclassifications had no impact on previously reported net income.New Accounting Pronouncements recent market transactions and cash flow projections. | |||
As a result of that testing, AEP determined that there was a net transitional impairment loss, which is reported as a cumulative effect of a change in accounting principle. | |||
See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets.SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets.In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized. | |||
Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP s and SWEPCo s intangible assets.SFAS 143, "Accounting for Asset Retirement Obligations , is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured atfairvalue and is capitalized as part of the related assets capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest)will be recognized each period as an operating expense in the statement of operations. | |||
The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects l&M and TCC) and possibly other obligations. | |||
AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities.SFAS 142, "Goodwill and Other Intangible Assets, was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. | |||
In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations. | |||
The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on L-1 2 In addition, the regulated transmission and distribution entities have asset retirement obligations related to the final retirement of certain transmission and distribution lines. There are also underground storage tanks located at various sites throughout the AEP System and PCB s are contained in certain transformer rectifier sets at power plants. The amounts relating to these obligations cannot be determined because the entities are not able to estimate the final retirement dates for these facilities. | |||
In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity from recording an expense for estimated costs associated with the removal or retirement of assets that result from other than legal obligations. | |||
The SEC Staff concluded that amounts that are included in accumulated depreciation related to estimated removal costs arising from other than legal obligations should be written off as part of the cumulative effect of adopting SFAS 143 unless the company is regulated under SFAS 71.Companies regulated under SFAS 71 may continue to include removal costs in depreciation rates but must quantify the removal costs included in accumulated depreciation as regulatory liabilities in footnote disclosure. | |||
The AEP registrant subsidiaries that are regulated entities have included estimated removal costs for non-legal retirement obligations in book depreciation rates.For non-regulated entities, including certain formerly regulated generation facilities, asset retirement obligations associated with wind farms, closure costs associated with power plants in the U.K. and possibly other items will be incurred.Also the amount of removal costs embedded in accumulated depreciation is expected to result in a favorable cumulative effect adjustment to net income. However, AEP and its registrant subsidiaries have not completed their determination of the net effect of these items on first quarter 2003 results of operations upon the adoption of the provisions of this standard.In August 2001, the FASB issued SFAS 144,"Accounting for the Impairment or Disposal of Long-lived Assets which sets forth the accounting to recognize and measure an impairment loss. This standard replaced, SFAS 121, "Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of. AEP adopted SFAS 144 effective January 1, 2002.The adoption of SFAS 144 did not materially affect AEP s results of operations or financial conditions. | |||
See Notes 3 and 13 for discussion of impairments recognized in 2002 by AEP and its registrant subsidiaries, affected by SFAS 144.In April 2002, the FASB issued SFAS 145,"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections'. | |||
SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. | |||
In 2003, for financial reporting purposes AEP and TCC will reclassify extraordinary losses net of tax on TCC s reacquired debt of $2 million for 2001.In October2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17 (EITF 02-3). EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. | |||
Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by generally accepted accounting principles. | |||
The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts entered into and inventory purchased through October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus will be reported as a cumulative effect of an accounting change. Such contracts and inventory will continue to be accounted for at fair value through December 31,2002. Energycontracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133.L-1 3 Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. | |||
Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. | |||
Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses.Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows.Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. | |||
Unrealized gain or loss at inception is recognized only when the fair value of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. | |||
AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts. | |||
In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. | |||
This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). | |||
Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entitys commitment to an exit plan.SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. | |||
SFAS 146 also establishes that the liability should initially be measured and recorded at fair value.The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.In November 2002, the FASB issued Interpretation No. 45, "Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees. | |||
This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No.34. The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition. | |||
See guarantee details discussed in Note 10.In December 2002, the FASB issued SFAS No.148, "Accounting for Stock-Based Compensation-Transition and Disclosure , which amends SFAS No. 123, "Accounting for Stock-Based Compensation | |||
.SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. | |||
Underthe fair value based method, compensation cost for stock options is measured when options are issued. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation. | |||
SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options.In November2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation: | |||
A Comparison of FASB L-14}} | |||
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| ML032970507 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 09/29/2003 |
| From: | Hyde R G South Texas |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| -RFPFR, G20, NOC-AE-31659820, STI 03001617 | |
| Download: ML032970507 (702) | |
Text
Nuclear Operating Company South Teas Procca Elecric Gcnerating Stailon PO. Box 28.9 Wdsworth, Texs 77483 September 29, 2003 NOC-AE-31659820 STI No.: 0300161 7 File No.: G20 1 OCFR50.71 (b)U. S. Nuclear Regulatory Commission Attention:
Document Control Desk Washington, D.C. 20555 South Texas Project Units 1 and 2 Docket Nos.: STN 50-498; STN 50-499 Annual Financial Reports Pursuant to the requirements of 1 OCFR50.71 (b), STP Nuclear Operating Company acting on behalf of itself and for AEP Texas Central Company, the Austin Energy, City Public Service of San Antonio, and Texas Genco, LP (formerly:
Reliant Energy), submits the attached current annual financial data for the South Texas Project Electric Generating Station.Should you require additional information, please contact Karen Wheaton at (361) 972-8698 or Ron Hyde at (361) 972-7992.Ron G. Hyde Supervisor, Corporate Insurance KMW Attachments:
a) AEP Texas Central Company Annual Report b) AEP Texas Central Company Form 1 0-K c) Austin Energy Annual Report d) City Public Service of San Antonio Annual Report e) Texas Genco, LP Annual Report f) Texas Genco, LP Form 1 0-K g) STP Nuclear Operating Company Financial Statement pwq0)O:\HUMtANRESOURCES\INSURANCE\ANNUAL MUST DOS\2003\NRC-ANNUAL FINANCIALS (2003).DOC STP Nuclear Operating Company cc: (paper copy)NOC-AE-31659820 File No.: G20 Page 2 (electronic copy)Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011 -8064 U. S. Nuclear Regulatory Commission Attention:
Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Richard A. Ratliff Bureau of Radiation Control Texas Department of Health 11 00 West 49th Street Austin, TX 78756-3189 Jeffrey Cruz U. S. Nuclear Regulatory Commission P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 A. H. Gutterman, Esquire Morgan, Lewis & Bockius LLP L. D. Blaylock City Public Service David H. Jaffe U. S. Nuclear Regulatory Commission R. L. Balcom Texas Genco, LP A. Ramirez City of Austin C. A. Johnson AEP Texas Central Company Jon C. Wood Matthews & Branscomb C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 F. H.G.R. G.R. D.S. C.RMS File Mallen, w/o Harrison, w/o Hyde, w/o Piggott, w/o Beaver N5001 N5001 N5001 N5014 N5014 N2002 AAERiICAN t ELECURJ I FP3Wly t r I r I v , I : .,-r, Ir-iiil'I i -i rwjrr I 2/'a 313/4Ic'I \
2002 -2001 C h a n g&-Net Income (Loss) (in millions)
.ongoing ' -- ---~~$95.7 $1,087-, as reported'.
(519) -S(l19 $971 (153.50 Earnings (Loss) Per Share *- -, --ngoing -- .-.. -S89$3.38:
-(4~as reported -11 57] $3.01 (1_2 Revenues o-(in billions)
-$14 6 $12.8 -i.--~Cash Dividends
-$2.40 $2.40,-Year*End Clos~~~ing Stock Price 527.33 $ 43.53 -(37 Book Value'at Year-End--
$20.85 $25.547-' ~ Total Assets (in billions):
- -. .$34.7 $39.3 U.S. Customers tat year-end) (in thousands)', 4,'975,. 4,930 0 Global Employment
--' 22,083 -2 3,4 (4.202rportedls f (.7 per share, adjusted fbr investmnent-Value and asset smpairmenits (33 07, p;er*- share), disposition and aSSEt iniPairmrents of SEEBOARD and CitiPo'wer (134 per share) sustainedean Ings improvement initiative restrncrurng costs ($0. 16 per share), asset impairments of Texas plants ($0.08 per share) and other items (10.04 per share), offset by~ a gain on disposition of Texas REPs ($0.23 per sharte), produces ongoing earigs of $2.89 peshae 201rpred earnings of $3.01 per share. adjuste for merger costs ($0.05 per share), neofo oso Pipe Line-related Enron purchase obligations
($0.08 per share), Severance accruals ($9.08 per share), nonre--curring adjustment
~~for taxes other than PIT, ($0.04 per share), disposition andwrt-onf assets -($0.01 -_per share) and an-extraordinary loss from discontinuance of regulatiyacontn firgene&ration in certain, stares ($0. 16 per share), offset by. the cumulative effect ofSA 3ransitoajumet(05) pdu es: -ongoing earnwg of $3.38 per shae .-- ..Thsdisso inldsfradloigsaeet ihin the mening of Section 2lEof the Secursies--- Exchangze Act of. 1934. These forward-looking statemnents reflect assumptions and involve a number of risks: aduncertainties.
Amiong the factors, both foreign and domestic, that could cause, acnual results to differ materiallyfrom forwvard-looking statements are: electric-load andl customer growth;, abnormnal weather ri-coditions; aiva-ilable sources -of and prices kii 6oal'and gas;_ availability ofgenerating capacity; risks related &to energy trading and contrctiont under contract; the speedl and degree to which comeiinisitoued
-- to our power generation business; the stiuceure and timing of a compedtitive market~ for 'electricity and its imat on prices; the abili ty to recover net regulitory assets,'other stranded costs and implementation coats-in c'onnection'with deregulation of generation in certain states; thetirniing of the im-pl'einmntstiois of AEP-'s '-resructurng plan, new legislation and government regulations; the ability to suiccessfully control costs; the ----success.o e business ventures;:
international developments affectinm u oeg netet; h economic clitnAlre and growthi in our service and trading 'territories,'
both dlomestic and fiorerign; th'e ability --of the, compansy to comply, with, and to successfly.
c aln~reenvironmental regultions and tosuc- T cessfulfly litigate claims that the comjpn iltdteCta n rAc;inflsti6iary rns litigation con- --cerniuig _AEP'smn'erger wihCSW; changes in electricity and gas miia et prices' n neetrts lcutos in foreign currency exchange rates, and other risks and unforescen events. ---.
4
ast year was extremely
-difficult for AEP. Due to a variety of factors, our earn-ings fell dramatically, as did our stock price. We deeply regret that our performance was far below our goals and your expectations.
In response to the negative developments in 2002, we are taking decisive steps to strengthen our bal-ance sheet and put the company back on track for value growth. We remain dedicated to providing low-cost electricity, superior customer service and an attractive return to investors.
A look back: Disappointing results Our utility operations performed reasonably well in 2002 despite rising costs, but the withering of wholesale markets in the U.S. and abroad cut into earnings from our wholesale operations.
As I'm sure you're aware, the wholesale arena -including power generation, associated assets and related marketing activity -had been highly profitable for us the past couple of years.AEP's ongoing earnings totaled $2.89 per share in 2002 compared with $3.38 in 2001. As-reported earnings were negative $1.57 per share, down from $3.01 the previous year.-r. Q mu. Writing down the value of poorly performing investments contributed to charges of approximately
$1.5 billion for 2002. Some of these write-offs, such as those related to telecommu-nications assets, were anticipated.
Others, such as a $415 million charge related to our generation assets in the United Kingdom, were not. We also incurred an equity reduction of nearly$600 million because of lost value in our pension plan assets. While the latter event lowered the equity on our balance sheet, the other items also reduced the earnings on our income statement.
On the positive side, despite last year's very tough market, we strengthened our balance sheet by $2 billion. We did it by selling non-core assets and issuing additional common stock and equity units. In 2002 we completed the sale of SEEBOARD, a regional electric company in the UK, and CitiPower, an Australian electricity provider.
AEP's first visit to the equity market in 20 years occurred last spring.Cash proceeds of approximately
$1.1 billion from thei asset sales and $990 million from the issuance of common stock and equity units were used to pay down debt.We did not attain our capitalization goal for 2002 of 45 percent equity and 55 percent debt but we expect t o-make significant progress this year. 2002 Sharehb Our long-term goal is 50 percent to 55 percent debt.A look ahead: Focus on the basics In 2003, we will focus on the basics. We are returning to a more traditional model of a regulated utility with a small commercial group dedicated to maximizing the value of .our generation fleet, which is the largest in the United States.S&P Electric A Currently, we think AEPs traditional utility Utlity Index business 1will perform at roughly the same ...............
level as last year and the wholesale business will have a somewhat weaker year. We project 2003 ongoing earnings in the range of $2.20 to $2.40 per share, including the dilution from additional equity issued in this year's older Return executive management will not be paid 0 this year. In addition, we expect to pare our-5 capital expenditures forecast for this year by to $200 million, to $1.5 billion..,i,:* -15: I .;I......EP CL cE: E-c q: _CA: E0:E-E o --o a si::;.w:¢: 0..X.,-.T :0 E f: first quarter.* O Our decision to recommend a reduction in the quarterly dividend of about 40 percent.........
-25 E: to our Board of Directors came after consid--30 erable analysis andw as painful but neces-sary. Reducing the dividend to a quarterly rate of 35 cents per share, starting with the.40 : J, 0 Vsecond quarter, will result im annual cash S&P lndex ;savings of $340 million. This will imrnmedi-.............
ately improve retained earnings and create free cash flow to boost liquidity and pay down debt. We believe the dividend will still have significant value and produce an attractive yield.We began shedding assets to improve our balance sheet last year and anticipate that process will accelerate in--2003. Non-core assets are the most likely candidates for divestment.
This will be an orderly disposition.
Proceeds-will go toward debt reduction.
Our liquidity position is strong. We have $3.5 billion available in cash and credit facilities, and we had $1.2 billion in cash at the, end of last year. During 2003, we expect free cash flow of approximately
$130 million after i .i : .: :: i 0 E -: ..,:: i:: E i : -: E -i i~ ~ ~ ~ ......E .....-i .E dividends are paid.- -In 2003, we aim for year-end capitalization consistent with a strong&BBB rating. We will continue to seek To bolster our balance sheet, we plan to lower costs,.. reduce the quarterly dividend, dispose of additional non-core assets, maintain our liquidity and current lines of credit,'and maximize cash flow.A company-wide cost reduction program should result in sustainable net savings in operations and maintenance costs of approximately
$60 millhon when compared with 2002 actual expenditures, and more than $300 million when compared with previously projected 2003 expendi-tures. We reduced our work force by approximately 1,300 positions.
Based on 2002 performance, bonuses for senior opportunities for further debt reduction and to work with the rating agencies to ensure we're addressing their concerns.:.:
With deregulation at a standstill in much of our service area,.we are re-evaluating our corporate separation initiative.
The legal separation of our regulated and unregulated businesses is provided for in Texas and Ohio,_where generation is deregulated and customers in most areas are able to choose their electricity supplier.However, the cost savings and benefits for all customers of a company-wide separation are now uncertain.
We are exploring these issues with our regulators.
Our intent is to comply'with restructuring legislation in the states that provide for a legal separation and to maintain a functional:
separation elsewhere.--
w 1 1-state service territory, thanks in part to increased usage by residential customers.
AEP's Texas operations were a major contributor to last year's utility-related earnings improvement.
Customer ::`choice was introduced in January 2002 in most-areas of our Texas service territory.
AEP's obligation to supply .retail electric providers (REPs) in that state last year con-tributed $495 million to gross margin. Sale of our affiliat-ed REPs to Centrica, a leading retail energy provider, near the end of 2002 provided immediate cash proceeds of:$146 million. The transaction includes an arrangement through 2006 that allows AEP. to share in any increased earnings opportunities that develop in the Texas retail*market, protecting us against downside exposure.Even with deregulation stalled, many of the nearly 5 mil-lion customers linked to our Wires will benefit from rate freezes in their respective states for the next severlS years.: Utility operations:
Stable, predictable AEPs regulated operations generate stable, reasonably predictable revenue and earnings.
They have been a steady contributor to our performance all along. The mission of our regulated business unit is to provide safe,: cost-effective and reliable service to customers.
Ongoing earnings from utility operations in 2002 totaled$326 per, share, up from $39in 2001. Retail gross -margins rose $250 million in Texas, $178 million in Ohio and $91 million in other jurisdictions throughout AP's Transmission represents a significant piece of our regulated business.
AEP, following Federal EnergyRegulatory Commission (FERC) guidance, continues working toward transferring functional control of its 38,000-mile transmission network to regioa transmis-sion organizations, or RTOs. -.-You may recall that AEP was among the companies deeply involved in recent years in developing a proposed for-profit RTO called the Alliance.
Last spring, however, 3 FERC turned down our proposal, so we are pursuing affil-lation with PJM Interconnection for our eastern assets and the Midwest Independent System Operator in the west, 'At this point, we don't anticipate divesting our transmis-.
sion assets. We project RTO-related costs of $30 million i.to $40 million in 2003.
- 1 0 0 0 0-c U)0 a 0.0 S S U)N C 0 N S 0 0.U U S'Li S U E Wholesale investments:
Unmet expectations Our unregulated operations performed well below our projections in 2002. AEP's wholesale investments lost$45 -million or 13 cents per share. Some of these investments, such as our natural gas and barge-line holdings, contributed positively to earnings, but the UK generation we acquired in 2001 -the Fiddler's Ferry and Ferrybridge plants -posted a $59 million operating loss.The UK has proved to be a very disappointing and difficult market. The oversupply conditions worsened as the year progressed, particularly after the British gov-'ernment decided'to subsidize British Energy. The $415 million write-down of UK generation that I mentioned earlier. stems, from recent analyses showing that UK power prices won't recover to levels that will support the carrying value of the plants on our books at the original purchase price of roughly $1 billion.As I noted above, we will be looking to divest certain wholesale assets and the UK generation certainly will be considered.
An even greater loss is possible in the UK in 2003. We're evaluating the best way, to reduce earnings drags and preserve shareholder value in this investment.l E Other unregulated investments not related to our whole-sale business also fired poorly and are candidates for" i-divestment.
Our telecommunications business had a $36.-million operating loss. We are actively seeking buyers for this business.Energy marketing:
Asset focus.Most of the output of our generating units is committed to our retail customers.
The rest is marketed to other utilities and wholesale customers.
Our decision to greatly scale back our energy marketing and trading operations and concentrate on' optimizing the value of our assets is reducing our risk exposure and helping to preserve our creditrratings.
Net margins from trading activities declined by'$349 million last year because of our reduced activity and because earnings from trading in 2001 were exceptionally strong. C The outstanding net fair; value of trading contracts has fallen from approximately
$450 million to $250 millionA:0 over the past year. The average duration of our existing:-
trading book is year-end 2003 for gas and second-half 2004 for power.--0 Our risk management group continues to work closely with the trading group to ensure limits are enforced.We reduced value-at-risk limits by 50 percent last year..Environmental:
Compliance and beyond::: Coal-fired generation remains AEP's mainstay.
At the end of 2002, our generating capacity mix was 69 percent coal and lignite, 20 p1ercent natural gas, 8 percent nuclear and 3 percent wind, hydro and other.Use of fossilf Eels brings with it environmental expendi-'tures, but our customer prices remain among the lowest'-`in the regions where we operate.:
Our ongoing program to meet federal standards to con-trol nitrogen oxide emissions'will cost an estimated
- $1.3 'billion to $2 billion in capital expenditures.
AEP remains a leader in policy discussions and research to address environmnental concerns.
.We are actively promoting enactment of legislation to 4 .further reduce sulfur dioxide, nitrogen oxide and mercury emissions to address air quality issues' associated withL::',-
coal-fired generation.
AEP is one of the founding' members of the Chicago Climate Exchange' the first voluntary pilot program for trading greenhouse gas emission credits.We've committed to reducing our greenhouse gas emis-: sions by4 percent over the'next four years. AEP also is:: participating in a project, led by Battelle to assess ,, 0 i, 2 E i, i X , ,;~~~~~~~
.; ........................
whether deep injection of carbon dioxide into the earth is a feasible climate-change mitigation technology.
.:: Commitment to improve I want to thank our employees for their hard work during: these unsettling times in the power industry.
Assets are: AEP's strength, and our employees are our strongest
- tS ..I : ... t i. A ---E.........i-
assets. Their dedication, talent and continued commit--ment to our business mission are at the heart of our plan'.~~ ~ ~ ~ ~~~~~~ .... ... .for recovery in the year ahead.:::
- - ..: -::-:: :. : Stepping up to new duties last 'year were Holly, Koep -who was named to oversee our unregulated businesses:
after the departure of Eric van der Walde; nd To ..m. .....Hagan, head of our shared services organization.
Tomr: succeeded Joe' Vipperman, who retired last year after more than four decades of dedicated service.Last year was indeed difficult and 2003 also holds::many challenges.
But I believe the measures I have outlined will improve our performance, and we are C'committed to doing what it takes to rebuild the value of your investment.
E. Lin n Draper, Jr..Chairm~an, President
&Chief Executive Officer February 28, 2003....i 7:: , f iESE-E:::
.E : -. -:~ ~: 7 :: ; , 0:0 a, 0 C/)
2002 2001-Assets...Cash and Cash Equivalents
.1224 -Energy Trading and Derivative Contracts Current ..104B ; 26 Other Current Assets:::...3,842L Property.
Plant and Equipment 3ZA14 .Accumulated Depreciation and Amortization
.-- 1,V3..q .... .......d.. ..............
...............
......... ....... ....Net Property, Plant and Equipment
...2,8 V0..............
.............
..............
.............
.........
....Regulatory Assets 2,8 Other Assets ... ..Total .... .S24.741 Capitalization and Liabilities
.. .Energy.Trading and Derivative Contracts Current:~.
.$1,4$17 Other Current Liabilities 8,4 ..t4 Long-Term Debt .Deferred Income Taxes and Investment Tax Credits'47 Minoity Interest in Financing Subst iday .79 Other Liabilities
..34~a Total Liabilities Cumulative Preferred Stocks of Subsidiaries
.14 0: Common Shareholders' Eqluity _______Total I .... 341 1 __ _E : Full disclosure
'of all Capitalization Ratio 2002 2001 o fina~ncial information o .~~~~~~~~~~~~~~0.7%
.0.7%is included in the. '1 Long-Term De b-t Appendix A to the .....Proxy Statement.
CiShort-Term Debt.0.U ~ ~ ~ ~ ~ Minority Equity ~~~~~~~~~~~~~~~~~~~~
32.2% -49.3% 35.8% 42.8%~' referred Stock 32 F 14.4%..:~]:*
17.5%:
., , '- E .- , 7 -I ., -.7 11 I " I 1- : --I r --, 1 -1 , .,, P i --1: . I ...11 I E, n .. i. Revenues Expenses: Fuel and Purchased Eniergy Mainitenianceand Other Operation
- . .. .:::~~::~:
Non-Recoverable Merger Costs':, .:~~~~~~~~~~~.............
................
..... ......Asset Impairments
- Depreciation and Amortization
.Taxes Othe r Than Income Taxes Total Expenses Other.Income
...Investment Value and Other.Imnpairment Losses Other Expenses......
Income Before Interest, Preferred Dividends.
Minority Interest and Income Taxes Interest, Preferred Dividends and Minority Interest Income Taxes Income Before Discontinued Oprtin, xraordinary items and Cumu lative Effect Discontinued Operations
-Income (Loss) (net of tax)Extraordinary Losses (net of tax):.: Discontinu'ance of Regulatory Accounting for Generation Loss on Reacquired Debt:-Cumulative Effect of Accounting Change (net of tax)Net Income (Loss)Average Number of Shares Outstanding..
Earnings Per Share: ~.. .....Income Before Discontinued Opraions,.~~~~~~~~~~~~~~~~~~~~~~~.......
Extraordinary Items and Cumulative Effect..Discontinued Operationrs.
Extraordinary Losses: 1.~:: .: ,w C umulIat i ve Effect Net Income (Loss)Cash Dividends Paid Per Sha're7::-
TN.M.=Not Meaningful 2002 2001.S14,55 I $12,767 f-,6,307 4,944 3,710: 10 21 7 B67~~~~~~~~.
.-1,377 ~ 1,243*718: 667: 13,292 10,585 445K! 335 321 -321 j 1 87-.1,66. 2 2,330 831; 867;214 ~546 21 917 (190) ~86.1 (48): (2)S (~1) I $ 971 i3~~: 322 2 85: 0:i.26 (0.16)I (¶.57r $ 3.01 S 2.4c~ $ .40...% Change: 1.7 N.m F S C)S C)C)-u 0 S M 0 0 C,)C..0 0.0 C,)0.0.0.: w.-...11
--I 7 -: I % -1 , -" 1, --., -, -I , 1, ..-_ .- --ly .-A .., -.Jll-1 , , ., -, -i -i i,, -, -1 ; 1. I I : ", 'zi , ,_, --, '_ 1 -, 1 -% I I .7 1 1 1, _; , -., t ----.1 __ --I 1- -2002 Operating Activities
-: Net Income (Loss) M .591.;NtIcm Ls):f ; ::! .............
.... ..... .. ...............
........ ........... ... .... .... ..Plus: Discontinued Operations Loss (income)Net Income from Continuing Operations Depreciation and Amortization'
-.. .: :.Asset Impairments Investment Value and Other Impairments ,I~~~~~~~ ............ .. .. .. .. .. .. .. .. .. ........ .................... .. .... .. .Adjustmrents for Other Noncash Items and Working Capita!l (3.. AjsmnsfrOhrNnahiesa dWrigCptl.
-:. , ;................
...... ...........................................
I.............
... .wi : Net Cash Flows from Operating Activities i.,, ~ ~ ~ ~ ~ .... ...... ...... ....-.. .. .. .. ... .. .. ... .. .. .. ... .. .. ....................
Investing Activities:.
Construction Expenditures (1.. .... ..................
.... .......................................................................................
.......Purchase of Gas Pipe Line Purchase of UK Generation Purchase of Coal Company:.............. ...........................
............................................
..........
,......PurchaseofBargingOperations:
.-: F.Purchase of Wind Generation::
Proceeds from Sale of Retail Electric Providers.~~~~~~~~~~~~~~.
..................................... ........Proceeds from Sale of Foreign Investments
- ................................
...........
..................................................................,i.i., : 1 ^ di : i:-Proceeds from Sale of U.S. Generation Net Cash Flows used for Investing Activities
.E .,.,.,.,.,,,,.,.,,.,,,...,.,.,,,,...............
.. ..............................- --i.. ..Financing Activities
- .Fnanin.Aciviie...........::.
- ....... .........
.........................................
............
.... ..11..-.'.....r.
Issuance ofCommon Stock .:: I-ssuance of MinorityInterest
...........................................
.. ...... ...... ..... ...... ...... ..... ...... ... .Issuance of Equity Unit Senior Notes I~~~~~~...................I...........
..... ...............................
i^..........
.,,, .... ... .....Change in Long-term Debt (net)Retirement of Cumulative Preferred Stock~:;:liRetiementof~muitive~refrredtock-T .i;0i,,e.,..........I
..................................................................
..............
.. fs, Change in Short-term Debt (net)-Cagihottrebne).,
- .0,..........
..... ............................................
.........
., l......'....
Dividen'rds Paidon Coim'mon Stock .. ..> ,. ........K.! !..* -.*- *-- *--' ---- !*-- --- *'*- .* ---- -'5:: ....................................
.........
........ ...........
.. ..... ..}. .Other::: t,.er.. .. .. ........... ............ I.............. .. ....Z_. ... ....Net Cash Flows from (used for) Financing Activities Effect of Exchange Rate Changes on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents from Continuiing Operations Beginning of Period Cash and.Cas Equivalents fo otnigOeain n fPro-:. ':Net Increase (Decrease) in Cash: and Cash Equivalents from Discontinued Operations:
- .5B -: :-; 'Cash and Cash Equivalents from DisContinued Operations
-eginning of Period Cash and Cash Equivalents from Discontinued Operations -End of Period._2001 E i.e.$+fl.:0t t:,]"jft'. N s T;eq;fsi:48-T w7S,:*--oll ,.S..:...m.:.(usi54-. t'1' 'f ,.g,...X, ffi;' a@t.¢ si ,,,1 b', ,=.;,. : ii ! .d... N.. _D.. -i-i _z Rl k i N I N 1 n i S: W., E.r d's is i "!] l t l:' a:.>i-r0,: 0.: U,,, C3g 0: 0 0.0 E:_E u)C" C 0`.0:.a.0.: 0 L i Ul~'E 4 srr:^ :? -:* 4:..': n ;e .i-To the Shareholders and Board of Directors:: of American Electric Power Company, Inc.:-: We have audited the consolidated balance sheets of::: American Electric Power Company, Inc.,,and its subsidiaries as of December 31, 2002 and 2001, and the related consoli-dated statements of operations, common shareholders'
- .E ---: -: .:E::---; :.-- i-::f i~~~~~~. ... .... .E.::EE;:
-....equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. -These consolidated financial statements and our' report thereon dated February 21, 2003, expressing an unqualified opinion (which are not included herein) are included in.. .:::: -: --:- -.:: :E :: .:E.:: -.~~~~~~~. ....: .E ~fiEi. .-.-... : Appendix A to the proxy statement for the 2002 annual meeting of.shareholders. The accompanying condensed~~~~~~~~~~~~~~~~~~~~~... .... .... .... .-.consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on such condensed consolidated financial statents in relation to the complete consolidad -.statements in relation to the complete consolidated
- -
- S The'management of American Electric Power Company,:.:
Inc., is responsible for the integrity, representations and objectivity of the information in the Company's sumrmary annual report and condensed consolidated financial state-ments. The condensed consolidated financial statements are derived from the consolidated financial statements included..in Appendix A to the proxy statement, which has been prepared in conformity with generally accepted accounting
- principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations.
The information in other sections of this summary annual report is consistent with these statements..T:::he consolidated financial statements have been audited by Deloitte & Touche LLP, from which these condensed consolidated financial statements have been derived and whose report appears on this page. The'auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported inancial condition and results of operations. Their audit includes procedures believed by them to provide reasonable ,:assurance that the financial statements are free of material::: misstatement and includes an evaluation of the Company's internal control structure over financial reporting.
- .: : .-: -wq -.: Chairman, President
&Chief Executive Officer .Chief Financial Officer: financial statements. In our opinion, the information set forth in the accom-:-:.:: -_ _.: _ :: ._ :: .:: ..:: : : _ :: :: :::::::_ .: : ::._......
- .:: ..::. :.. ::::-::::.
panying condensed consolidated balance sheets as of December 31, 2002 and 2001, and the related condensed consolidated statements of operations and of cash flows fort:-.. .--~~~~~~~~~~~~~~~~~~~~~~~..... the years then ended is fairly stated in all material respects in relation to the basic consolidated financial statements-.-'-...:s from which it has been derived.a..e: :, :1* .>B U m U.* -u a B 0 0 N, C0 0.......... ...S S J: ..~ ~ ~ ~~~~~~~~~~~ ~ ..... ..-_-~~~~~~~~~~~~~~~~w ..Columbus, Ohio February 21, 2003 Board of Directors: Front row letf to right Donald G.Smith, E.R. Brooks, E. Linn Draper, Jr.,John P. DesBarres, Robert W. Fri Bac row left to right.: Donald M. Carlton, William R.Howell, Linda Gillespie Stuntz, LeonardJ. Kujawa, Richard L.Sandor, Kathryn D. Sullivan .Thomas V. Shockley, 111, Lester A. Hudson, Jr.: Dr. E. Linn Draper, Jr., 61 .-Chairman, President& Chief Executive Officer: (1992) : E.R. Brooks, 65. -Retired Chairman.a & Chief Executive Officer, Central & South West Corp..Granbury, Texas (2000) .: Dr. Donald M. Carlton, 65 Retired President& Chief Exccutive Officer, Radian International, LLC.Austin, Texas (2000) .!N. .John P. DesBarres, 63 Investor/Consultante Park City, Utah : (997) LH.N.r Robert W. Fri 67: Visiting Scholar, Resources for the FutureL Washington, D.C.(1995)?7:7-m 0 0 U, 0.0 M..0 Co..0 LU 0 0C1 William R. Howell 67 Chairman Emeritus, J.C. Penney Company, Inc.Dallas, Texas (2000) .H.P Dr. Lester A. Hudson, Jr., 63 Professor of Business Strategy, Clemson University Greenville, South Carolina:':: (18)A-DJ : : i Leonard J. Kujawa, 70 International Energy Consultant Atlanta, Georgia:: (1997) D.'-Dr. Richard L Sandor, 61 Chairman & Chief Executive Officer, Environmnental Financial. Products, LLC Chcago, Illinois (2000) Drf~g Thomas V. Shockley, III, 57 Vice Chairran: (2000)Donald G. Smith, 67 Chairman, President& Chief Executive Officer, Roanoke Electric Steel Corp.Roanoke, Virginia (1994) N.?- -: Linda Gillespie Stuntz, 48 Partner-: Stuntz, Davis & Staffier, P.C.Washington, D.C.(1993) "- 'Committees of the Board: The chairman is listed in ().A Audit (Carlton),.
- Directors and Corporate Governance (Hudson),.-..
- Executive (Draper), Finance (Stunt), H Human Resources (DesBarres), N Nuclear Oversight (Sullivan),:
Policy (Fri)Dr. Kathryn D. Sullivan, 51 President & Chief Executive Officer, Center of Science & Industry Columbus, Ohio (1997) A N.r , --r 7 , -r -e, ...-, a "'. ---7 il , 4 4. 1 .I t- :, -i _- 7 -i'. -t! E i ., ... , %American Electric P-Service Corporatior ---I'ow nI:.. ~:: :. ---.. : ..: .-:.L :, : .-Office of the Chairman r Front row Iet to right: Holly K. Koeppel, E. Irnn Draper, Jr., Thomas M. Hagan, Susan Tomasky, Bac row lift to right: Robert P. Powers, Henry W. Fayne, Thomas V. Shockley, III American Electri Company. Inc.E. Linn Draper, Jr.Chairman, President Chief Executive Offi Thomas V. Shocklh Vice Chairman: c Power and Dy,Il Offic ce.Lito.icer E. Unn Draper, Jr.: Chairman, President and Chief Executive Officer Thomas V. Shockley, lli:Vice Chairman and-:'H : i;Chief Operating Officer Henry W. Fayne Executive Vice President Thomas M. Hagan --Eecutive Vice President -Shared Services Holly K. Koeppel Executive Vice President Robert P. Powers Executive Vice President -Generation -117 Susan Tomasky .:- --: Executive Vice President-Pollcy, Fiance and:.Strategic Planning, and::Assistant Secretary Melinda S. Ackerman:? Senior Vice President -Human Resources Nicholas J. Ashooh Senior Vice President-Corporate Communuications J. Craig Baker.Seniomor Vice President -Regulation and Public Polic IA. Christopher Bakken, III ,,.Senior Vice President .- -'Nuclear Operations i: .: ... .li .E:E ..... E i !-:iL i.ver;0-3 0:0:; i,0-f; -t,;.:: :: :::::::: :: : if -:::: -:- -,* :! i: i E i.: f i -. .:.f i-D:: :S.-..::: -:.:.-:00-S't.t -::::f:: ',,' i'-....t:' T-ttT, i i :000 'l::gE: :-:: if::-i E E i: ' ;'::"* ....:!g:-t,,-*: .i-:-. :i: [-... ...: -S-.E : i t! t :,.s ' f' ': E .f --i 0 ;$ tiE: 'i', t-;-,.,.-;fX,,,..,404 icye: ::... -: :.iiE--T ---fiS if -ff. -:-.tt';; -- i.E .-EE.E if i:: iL iE:EE:iE::
- E-.i.:: -....: .:. i.: i....i. i: ..---:::::::: ::::: i -" ':.':: : :E-: tiEd E ;-, i:: Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer Jeffrey D. Cross Senior Vice President, General Counsel and : Assistant Secretary.
Joseph Hamrock Senior Vice President: -General Services :: Dale E. Heydlauff Senior Vice President -Governmental and Environmental Affairs Michelle S. Kalnas Senior Vice President -Supiply Chain, 'Richard E. Munczinski Senior Vice Preside'nt -Corporate Planning .:-and Budgeting: Armando A. Pe a (l}Senior Vice President -Finance and Treasurer Michael W.: Rencheck .-Senior Vice President -Technical Services:: m William L Sigmon, Jr.:-: Senior Vice President -:: 0 Fossil and Hyro H.Generation -Scott N. Smith -Senior Vice President .-. : W and Chief Risk Officer:0 3 03-........ .-(-,....::.....L- -- i i t i O* iE i,, E iSE, i .:: i -:_:~Henry W. Fayne Vice President Armando A. Pe a.Treasurer Susan Tomasky Vice President, Secnr and Chief Financial Joseph M. Buonaii ,.-1 ,, , ...E Controller and..Chief Accounting 0 I i.','I I % -.I .I"" " n-, .;_ -.1 : fil, .,-,R 2-71N7-30, _,_-:,_1_Annual Meeting -The 96th annual meeting of shareholders of American Electric Power Company will be held at 9:30 a-m.Wednesday, April 23, 2003, at The Ohio State University's Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio. Admission is by ticket only. To obtain a ticket, please note the instructions in the Notice of Annual Meeting mailed to shareholders or call the Company. If you hold your shares through a broker, please bring proof of share ownership as of the record date.Shareholder Inquiries -If you have questions about your account, contact the Company's transfer agent, listed below. You should have your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the shareholder's approval or appropriate documents. Transfer Agent & Registrar EquiServe Trust Company, N.A.(formerly First Chicago Trust Company of New York)P.O. Box 43069 Providence, RI 02940-3069 Telephone Response Group: 1-800-328-6955 Internet address: www.equiserve.com Hearing Impaired #: TDD: 1-800-952-9245 Internet Access to Your Account -If you are a registered shareholder, you can access your account information through the Internet at www.equiserve.com. Information about obtaining a password is available toll-free at 1-877-843-9327. Replacement of Dividend Checks -If you do not receive your dividend check within five business days after the dividend'pay-ment date, or if your check is lost, destroyed or stolen, you should notify the transfer agent for a replacement. Lost or Stolen Stock Certificates -If your stock certificate is lost, destroyed or stolen, you should notify the transfer agent immediately so a 'stop transfer' order can be placed on the missing certificate. The transfer agent then will send you the required documents to obtain a replacement certificate. Address Changes -It is important that we have your current address on file so that you do nor become a lost shareholder. Please contact the transfer agent for address changes fbr both record and dividend mailing addresses. We also can provide automatic seasonal address changes.Stock Transfer -Please contact the transfer agent if you have questions regarding the transfer of stock and related legal requirements,. -Dividend Rei'nvestment and Direct Stock Purchase Plan -A Dividend Reinvestment and Direct Stock Purchase Plan is avail-able to all investors. It is an' economical and convenient method of purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent... i Direct Deposit of Dividends -The Company does offer electronic deposit of your dividends. Contact the transfer agent for details.Stock Held in Brokerage Account ('Street Name') -When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker's name or 'street name.' AEP does not know the identity of idivdual shareholders who hold their shares in this manner, we simply know that a broker holds a certain number of shares which'may be for any number of customers. If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any questions you may have about your account should be directed to your broker.How to Consolidate Accounts -If you want to consolidate your separate accounts into one account, you should contact the transfer agent to obtain the necessary instructions. When accounts are consolidated, it' may be necessary to reissue the stock certificates.
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- ; A :. : .How to Eliminate Duplicate Mailings -If you want to maintain more than one account but eliminate additional mailings of annual reports, you may do so by contacting the transfer agent, indicating the names you wish to keep on the mailing list for annual reports and the names you wish to delete. This will affect only these mailings; dividend checks and proxy materials will continue to be sent to each accountI:
IdE i-Stock Trading -The Company's common stock is traded princi-pally on the New York Stock Exchange under the ticker symbol.AER AEP stock has been traded on the NYSE for 54 years.Taxes on Dividends -The Company paid $2.40 in cash dividends in 2002, all of which' are taxable for federal income tax purposes.AEP has paid consecutive quarterly dividends since 1910.Shareholder Direct -An array of timely recorded messages.about AEP, including dividend and earnings information and recent news releases, is available from AEP Shareholder Direct at 1-800-551-lAEP (1237) anytime day or night. Hard copies of information can be obtained via fax or mail. Requests for annual reports, 10-K's, 10-Q's, Proxy Statements and Summary Annual I Reports should be made through Shareholder Direct.Financial Community Inquiries -Institutional investors or secunities analysts who have questions about the Company;should direct inquiries to Bette Jo Rozsa, 614-716-2840, bjrozsa@aep.com, orJulie Sloar, 614-716-2885, jsloat@aep.com; individual shareholders should contact Kathleen Kozero, : 614-716-2819, klkozero@aep.com, or April Dawson, 614-716-2591 addawson aep.com.Internet Home Page -Information about AEP, including financial documents, SEC filings, news releases and customer service information, is available on the Company's home page,:, on the Internet at www..aep.coml .Annual Report and Proxy Materials -You can receivei: future annual reports, proxy statements and proxies electronically rather than by mail; if you are'a registered holder, log on to wvww.econsent.comlaep.- If you hold your shares in street name, contact your broker.-7IEI:Ii; Cd, M E: E.Li) WA MT NO MN i ME OR I0 C.. : F:ti'S .C) N- W I-l, So WY M!VT NH NY I MA CT RI NJ[A NE NV UT MD CA co NM KS MO DE ,, , -OKDr TN NC AZ AR LA SC MS AL GA-AEP service area-; Transmission lines FL More than 42,000 megawatts of electric generating capacity, including the largest generation fleet in the U.S.-38,000 circuit miles of transmission lines 186,000 miles of distribution lines:.128 billion cubic feet of gas storage 6,400 miles of natural gas pipeline 7,000 rail cars 1,800.barges and 37 tug boats .Annual coal production capability of 10 million tons American Electric Power owns and operates more than;'42,000 megawatts of generating capacity in the United.States and select international markets and is the largest electricity generator in the U.S. AEP is also one of the largest electric utilities in the United States, with almost 5 million customrers linked to AEP's electricity transmission and distribution grid. Those customers are located in 11 states -Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio Oklahoma, Tennessee, Texas, Virginia and West Virginia. The company's distribution service area:*6covers 197,500 square miles., Outside the United States, AEP holds interests in the United Kingdom, Australia, Brazil, China, Mexico and the Pacific Regions bs i C Ohio..AEP is based in Columbus, Ohio. 4 f 0;>z -z e
2002 Annual Reports American Electric Power Company, Inc.AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Audited Financial Statements and Management s Discussion and Analysis AMERICAN ELECTRIC POWER AEPh.rnfefica:s EnewTy Partner' Contents Page Glossary of Terms i Forward Looking Information iv AEP Common Stock and Dividend Information v American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Operations A-9 Consolidated Balance Sheets A-10 Consolidated Statements of Cash Flows A-12 Consolidated Statements of Common Shareholders Equity and Comprehensive Income A-13 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-14 Schedule of Consolidated Long-term Debt of Subsidiaries A-15 Index to Combined Notes to Consolidated Financial Statements A-1 6 Independent Auditors' Report A-17 Management's Responsibility A-18 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Combined Notes to Financial Statements B-8 Independent Auditors' Report B-9 AEP Texas Central Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income C-5 Consolidated Statements of Retained Earnings C-6 Consolidated Balance Sheets C-7 Consolidated Statements of Cash Flows C-9 Consolidated Statements of Capitalization C-1 0 Schedule of Long-term Debt C-1I Index to Combined Notes to Consolidated Financial Statements C-13 Independent Auditors' Report C-1 4 AEP Texas North Company Selected Financial Data D-A Management's Narrative Analysis of Results of Operations D-2 Statements of Operations and Statements of Comprehensive Income D-4 Statements of Retained Earnings D-5 Balance Sheets D-6 Statements of Cash Flows D-8 Statements of Capitalization D-9 Schedule of Long-term Debt D-1 0 Index to Combined Notes to Financial Statements D-1 1 Independent Auditors' Report D-1 2 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Discussion and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income E-5 Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-1 0 Schedule of Long-term Debt E-1 I Index to Combined Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-1 3 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Narrative Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income F-4 Consolidated Statements of Retained Earnings F-5 Consolidated Balance Sheets F-6 Consolidated Statements of Cash Flows F-8 Consolidated Statements of Capitalization F-9 Schedule of Long-term Debt F-1 0 Index to Combined Notes to Consolidated Financial Statements F-11 Independent Auditors' Report F-1 2 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data G-1 Management's Discussion and Analysis of Results of Operations G-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income G-5 Consolidated Statements of Retained Earnings G-6 Consolidated Balance Sheets G-7 Consolidated Statements of Cash Flows G-9 Consolidated Statements of Capitalization G-10 Schedule of Long-term Debt G-1I Index to Combined Notes to Consolidated Financial Statements G-12 Independent Auditors' Report G-13 Kentucky Power Company Selected Financial Data H-1 Management's Narrative Analysis of Results of Operations H-2 Statements of Income, Statements of Comprehensive Income and Statements of Retained Earnings H4 Balance Sheets H-5 Statements of Cash Flows H-7 Statements of Capitalization H-8 Schedule of Long-term Debt H-9 Index to Combined Notes to Financial Statements H-10 Independent Auditors' Report H-11 --Ohio Power Company Selected Financial Data 1-1 Management's Discussion and Analysis of Results of Operations 1-2 Statements of Income and Statements of Comprehensive Income 1-5 Statements of Retained Earnings 1-6 Balance Sheets 1-7 Statements of Cash Flows 1-9 Statements of Capitalization 1-10 Schedule of Long-term Debt 1-11 Index to Combined Notes to Financial Statements 1-12 Independent Auditors' Report 1-13 Public Service Company of Oklahoma and Subsidiary Selected Consolidated Financial Data J-1 Management's Narrative Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income J-4 Consolidated Statements of Retained Earnings J-5 Consolidated Balance Sheets J-6 Consolidated Statements of Cash Flows J-8 Consolidated Statements of Capitalization J-9 Schedule of Long-term Debt J-10 Index to Combined Notes to Consolidated Financial Statements J-1 1 Independent Auditors' Report J-1 2 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data K-1 Management's Discussion and Analysis of Results of Operations K-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income K-4 Consolidated Statements of Retained Earnings K-5 Consolidated Balance Sheets K-6 Consolidated Statements of Cash Flows K-8 Consolidated Statements of Capitalization K-9 Schedule of Long-term Debt K-1 0 Index to Combined Notes to Consolidated Financial Statements K-1 I Independent Auditors' Report K-1 2 Combined Notes to Financial Statements L-1 Registrants Combined Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters M-1 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below: Term Meaning 2004 True-up Proceeding ........ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs.AEGCo .. ................... AEP Generating Company, an electric utility subsidiary of AEP.AEP .................. American Electric Power Company, Inc.AEP Consolidated .................... AEP and its majority owned consolidated subsidiaries. AEP Credit .................. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and non-affiliated domestic electric utility companies. AEP East companies ............... APCo, CSPCo, I&M, KPCo and OPCo.AEPR .................. AEP Resources, Inc.AEP System or the System ....... The American Electric Power System, an integrated electric utility system, owned and operated by AEP s electric utility subsidiaries. AEPSC .................... American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. AEP Power Pool .................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. AEP West companies ............... PSO, SWEPCo, TCC and TNC.AFUDC .................... Allowance forfunds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant.Alliance RTO .. .................. Alliance Regional Transmission Organization, an ISO formed byAEP and four unaffiliated utilities (the FERC overturned earlier approvals of this RTO in December 2001).Amos Plant ................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.APCo ..................... Appalachian Power Company, an AEP electric utility subsidiary. Arkansas Commission ............. Arkansas Public Service Commission. Buckeye .................. Buckeye Power, Inc., an unaffiliated corporation. CLECO .................. Central Louisiana Electric Company, Inc., an unaffiliated corporation. COLI .................. Corporate owned life insurance program.Cook Plant .................. The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.CPL .................... Central Power and Light Company [legal name changed to AEP Texas Central Company (TCC) effective December 2002]. See TCC.CSPCo .................... Columbus Southern Power Company, an AEP electric utility subsidiary. CSW ...... ............ Central and South West Corporation, a subsidiary of AEP (Effective January 21,2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).CSW Energy ................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.CSW International .................... CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States.D.C. Circuit Court .................... The United States Court of Appeals for the District of Columbia Circuit.DHMV ................... Dolet Hills Mining Venture.DOE .................. United States Department of Energy.ECOM ................... Excess Cost Over Market.ENEC .................... Expanded Net Energy Costs.EITF .................... The Financial Accounting Standards Board s Emerging Issues Task Force.ERCOT .................. The Electric Reliability Council of Texas.EWGs .................. Exempt Wholesale Generators. FASB .................. Financial Accounting Standards Board.Federal EPA .................. United States Environmental Protection Agency.i FERC ................ Federal Energy Regulatory Commission. FMB ..... ........... First Mortgage Bond.FUCOs ...... .......... Foreign Utility Companies. GAAP ..... ........... Generally Accepted Accounting Principles. I&M ................ Indiana Michigan Power Company, an AEP electric utility subsidiary. ICR ................ Interchange Cost Reconstruction. IPC .... ............ Installment Purchase Contract.IRS .... ............ Internal Revenue Service.IURC ................ Indiana Utility Regulatory Commission. ISO .... ............ Independent System Operator.Joint Stipulation .. ................ Joint Stipulation and Agreement for Settlement of APCo s WV rate proceeding. KPCo ................ Kentucky Power Company, an AEP electric utility subsidiary. KPSC ................ Kentucky Public Service Commission. KWH .................. Kilowatthour. LIG ................ Louisiana Intrastate Gas.Michigan Legislation ................ The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.MISO .................. Midwest Independent System Operator (an independent operator of transmission assets in the Midwest).MLR ................ Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.Money Pool ........ ........ AEP System s Money Pool.MPSC ................ Michigan Public Service Commission. MTM ..... ........... Mark-to-Market. MTN ..... ........... Medium Term Notes.MW ................ Megawatt.MWH ..... ........... Megawatthour. NEIL ..... ........... Nuclear Electric Insurance Limited.NOx ................ Nitrogen oxide.NOx Rule ................ A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate.NP .................. Notes Payable.NRC ................ Nuclear Regulatory Commission. Ohio Act ................ The Ohio Electric Restructuring Act of 1999.Ohio EPA ................ Ohio Environmental Protection Agency.OPCo ................ Ohio Power Company, an AEP electric utility subsidiary. OVEC ................ Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.PCBs ................ Polychlorinated Biphenyls. PJM .................. Pennsylvania New Jersey Maryland regional transmission organization. PRP ................ Potentially Responsible Party.PSO ................ Public Service Company of Oklahoma, an AEP electric utility subsidiary. PUCO ................ The Public Utilities Commission of Ohio.PUCT .................. The Public Utility Commission of Texas.PUHCA ................ Public Utility Holding Company Act of 1935, as amended.PURPA ................ The Public Utility Regulatory Policies Act of 1978.RCRA .... ............ Resource Conservation and Recovery Act of 1976, as amended.Registrant Subsidiaries ............. AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.REP ................ Retail Electric Provider.Rockport Plant ................ A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and l&M.RTO ................ Regional Transmission Organization. ii SEC ............. Securities and Exchange Commission. SFAS .... ......... Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.SFAS 71 ............... Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. SFAS 101 ............... Statement of Financial Accounting Standards No. 101, Accounting forthe Discontinuance of Application of Statement 71.SFAS 133 ............. Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. SNF ............. Spent Nuclear Fuel.SPP ............... Southwest Power Pool.STP ............... South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an AEP electric utility subsidiary. STPNOC ..... ........ STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including TCC.Superfund ............. The Comprehensive Environmental, Response, Compensation and Liability Act.SWEPCo ............... Southwestern Electric Power Company, an AEP electric utility subsidiary. TCC ............. AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central Power and Light Company (CPL)].Texas Appeals Court ............. The Third District of Texas Court of Appeals.Texas Legislation .. ............. Legislation enacted in 1999 to restructure the electric utility industry in Texas.TNC ............. AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas Utilities Company (WTU)].Travis District Court ............. State District Court of Travis County, Texas.TVA ............... Tennessee Valley Authority. U. ............. The United Kingdom.UN ............. Unsecured Note.VaR ............... Value at Risk, a method to quantify risk exposure.Virginia SCC ............. Virginia State Corporation Commission. WV ............... West Virginia.WVPSC ............... Public Service Commission of West Virginia.WPCo ............. Wheeling Power Company, an AEP electric distribution subsidiary. WTU ............. West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective December 2002]. See TNC.Yorkshire ............... Yorkshire Electricity Group pic, a U.K. regional electricity company owned jointly by AEP and New Century Energies until April 2001.Zimmer Plant ............. William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary. iii FORWARD LOOKING INFORMATION These reports made byAEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21 E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:* Electric load and customer growth.* Abnormal weather conditions. .Available sources and costs of fuels.* Availability of generating capacity.* The speed and degree to which competition is introduced to our service territories.
- The ability to recover stranded costs in connection with possible/proposed deregulation.
- New legislation and government regulation.
- Oversight and/or investigation of the energy sector or its participants.
- The ability of AEP to successfully control its costs.* The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile.* International and country-specific developments affecting AEP's foreign investments including the disposition of any current foreign investments and potential additional foreign investments.
.The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.* Inflationary trends.* Electricity and gas market prices.* Interest rates.* Liquidity in the banking, capital and wholesale power markets..Actions of rating agencies.* Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. .Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.iv AEP Common Stock and Dividend Information The quarterly high and low sales prices and the quarter-end closing price for AEP common stock and the cash dividends paid per share are shown in the following table: Quarter-end Quarter Ended High Low Closing Price Dividend March 2002 $47.08 $39.70 $46.09 $0.60 June 2002 48.80 39.00 40.02 0.60 September 2002 40.37 22.74 28.51 0.60 December2002 30.55 15.10 27.33 0.60 March 2001 $48.10 $39.25 $47.00 $0.60 June 2001 51.20 45.10 46.17 0.60 September 2001 48.90 41.50 43.23 0.60 December 2001 46.95 39.70 43.53 0.60 AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003 management recommended thatthe Company reduce dividends by approximately 40% after payment of the March 2003 dividend which was approved by the Company s Board of Directors at the current level of $0.60 per share.v AMERICAN ELECTRIC POWER COMPANY, INC.AND SUBSIDIARY COMPANIES AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES selected consolidated Financial Data Year Ended December 31, 2002 2001 2000 1999 1998 OPERATIONS STATEMENTS DATA (in millions): Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080 operating Income 1,263 2,182 1,774 2,061 2,046 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 21 917 180 869 859 Discontinued operations Income (Loss) (190) 86 122 117 116 Extraordinary Losses -(50) (35) (14) _Cumulative Effect of Accounting change Gain (Loss) (350) 18 ---Net Income (Loss) (519) 971 267 972 975 December 31. 2002 2001 2000 1999 1998 BALANCE SHEET DATA (in millions): Property, Plant and Equipment $37,857 $37,414 $34,895 $33,930 $32,400 Accumulated Depreciation and Amortization 16.173 15.310 14.899 14.266 13.374 Net Property, Plant and Equipment $22,104 $19,996 S1 5664 Total Assets $34,741 $39,297 $46,633 $35,296 $33,418 Common shareholders' Equity 7,064 8,229 8,054 8,673 8,452 Cumulative Preferred Stocks of Subsidiaries* 145 156 161 182 350 Trust Preferred securities 321 321 334 335 335 Long-term Debt* 10,496 9,505 8,980 9,471 9,215 Obligations under capital Leases* 228 451 614 610 539 Year Ended December 31. 2002 2001 2000 1999 1998 COMMON STOCK DATA: Earnings per Common share: Before Discontinued operations, Extraordinary Items and cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70 Discontinued Operations (0.57) 0.26 0.38 0.36 0.36 Extraordinary Losses -(0.16) (0.11) (0.04) -cumulative Effect of Accounting change (1.06) 0.06 ---Earnings (Loss) Per share (1.5) $3.1 $0-83 $ 3.03 $_3.0 Average Number of shares Outstanding (in millions) 332 322 322 321 318 Market Price Range: High $ 48.80 $51.20 $48-15/16 $48-3/16 $53-5/16 Low 15.10 39.25 25-15/16 30-9/16 42-1/16 Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16 cash Dividends on Common** $ 2.40 $2.40 S2.40 $2.40 $2.40 Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%Book value per share $20.85 $25.54 $25.01 $26.96 $26.46*Including portion due within one year. Long-term Debt includes Equity unit senior Notes.**Based on AEP historical dividend rate. See "Common stock and Dividend Information (on page v) regarding the potential reduction of future dividends. A-1 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Managements Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S. We provide generation, transmission and distribution service to almost five million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. We have a vast portfolio of assets including:
- 38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in our market areas.4,000 megawatts of generating capacity in the U.K., a countrywhich is currently experiencing excess generation capacity* 38,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S.* 186,000 miles of distribution lines that support delivery of electricity to our customers premises a Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity)* 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of gas storage facilities Business Strategy We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets. We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business.Through our utility operations focus, we intend to be the energy and low cost generation provider of choice. We have ample generation to meet our customers needs.We have a cost advantage resulting from AEP s long tradition of designing, building and operating efficient power plants and delivery networks.
Our customers continue to show top quartile level of satisfaction. We provide safe and reliable sources of energy.Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors. We are addressing many challenges in our unregulated business. We have already substantially reduced our trading activities. We have written down the value of several investments to reflect deterioration in market conditions. We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy. We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling. Transition rules for Michigan and Virginia do not require legal separation. Deregulation is no longer an expectation in the foreseeable future in the other states where we operate.Our strategy for the core business of utility operations is to:.Maintain moderate but steady earnings growth* Maximize value of transmission assets and protect our revenue stream in an RTO membership environment
- Continue process improvement to maintain distribution service quality while, at the same time, further enhancing financial performance
- Optimize generation assets through increased availability and sale of A-2 excess capacity Manage the regulatory process to maximize retention of earnings improvement while providing fair and reasonable rates to our customers We remain very focused on credit quality and liquidity as discussed in greater detail later in this report.We are committed to continually evaluating the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and sustainable shareholder value. Any investment dispositions could affect future results of operations, cash flows and possibly financial condition.
2002 Overview 2002 was a year of rapid and dramatic change for the energy industry, including AEP, as the wholesale energy market quickly shrank and many of its participants exited or significantly limited future trading activity.Investors lost confidence in corporate America and the economy stalled. Investors demand for stability, predictable cash flows, earnings, and financial strength have replaced their demand for rapid growth.Our wholesale business did not perform well.We had significant losses in options trading in the first half of the year and new investments performed well below our expectations. We focused on financial strength by:* Issuing approximately $1 billion in common stock and equity units.Retiring debt of approximately $3 billion through the sale of two foreign retail utility companies in the U.K.(SEEBOARD) and Australia (CitiPower)
- Establishing a cash liquidity reserve of$1 billion at year-end See Financing Activity in Managements Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters in section M for an overview of all changes to capital structure.
We also focused on:* Implementing an enterprise-wide risk management system* Completing a cost reduction initiative which we expect to result in sustainable net annual savings of more than $200 million beginning in 2003* Eliminating or reducing future capital requirements associated with non-core assets We have redirected our business strategy by:* Scaling back trading activities to focus principally on supporting our core assets* Selling our Texas retail business.Proposing the sale of a significant portion of the Texas unregulated generation assets Outlook for 2003 We remain focused on the fundamental earnings power of our utility operations, and we are committed to strengthening our balance sheet. Our strategy for achieving these goals is well planned:* First, we will continue to identify opportunities to reduce our operations and maintenance expense.* Second, we will find opportunities to reduce capital expenditures.
- Third, management recommended a 40% reduction in the common stock dividend beginning in the second quarter to a quarterly rate of $0.35 per share. This will result in annual cash savings of approximately
$340 million and should improve our retained earnings as well as create free cash flow to improve liquidity and pay-down outstanding debt.* Fourth, we plan to evaluate and, where appropriate, dispose of non-core assets. Proceeds from these sales will be used to reduce debt..Fifth, we will continue to evaluate the potential for issuing additional equity to further strengthen our balance sheet and maintain credit quality.We remain committed to being a low cost provider of electricity, to serving our A-3 customers with excellence and to providing an attractive return to investors. We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets.Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters. We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors. Results of Operations In 2002, AEP s principal operating business segments and their major activities were:* Wholesale: o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity trans-mission o Domestic electricity distri-bution* Other Investments o Energy Services Net Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001. The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. In 2002, the Company s Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3).Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP s wholesale marketing business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. The effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron s bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.Our wholesale business has been affected by a slowing economy. Wholesale energy margins and energy use by industrial customers declined in 2002 and 2001.Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO.Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues in 2002 and 2001.Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001.A-4 Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be more volatile. See 'Market Risks section for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. Revenues Increase AEP s total revenues increased 14% in 2002 and 15% in 2001. The following table shows the components of revenues: For The Year Ended December 31 2002 2001 2000 (in millions)WHOLESALE: Residential $ 3,713 commercial 2,156 Industrial 1,903 other Retail customers 385 Electricity Marketing (net) 2,227 unrealized MTM Income-Electric 136 other 1,397 Less: Transmission and Distribution Revenues Assigned to Energy Delivery* (3.551)wholesale Electric 8.366 S 3,553 2,328 2,388 S 3,511 2,249 2,444 419 414 802 1,073 210 38 632 837 has had a major effect on the volume of wholesale power marketing especially in the short-term market.The increase in 2002 in wholesale revenues resulted from a 27% increase in trading volume associated with Wholesale Electricity which was offset by a continuing decrease in gross margins which began in the fourth quarter of 2001, and an increase in residential sales as a result of favorable weather conditions in the third quarter 2002.In addition OtherWholesale electric revenues increased due to the mid-year 2001 acquisition of barging and coal mining operations as well as the recognition of revenues for generation projects completed for third parties. The increase in 2002 Wholesale Gas revenues resulted from a full year of HPL operations compared to a partial year from our acquisition date in July 2001, offset by a decrease in the results from financial trading and MTM unrealized losses.Other Investments revenue decreased in 2002 due to the elimination of factoring of accounts receivable of an unaffiliated utility.Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 1).Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in 2001. This decrease was due to the economic slow down which began in late 2001. Sales to residential customers rose 5%due to weather related demand in 2002. The economic slow down reduced demand and wholesale prices especially in the latter part of 2001.i (3.356) (3.174)6,97 7,392 Gas Marketing (net) 3,021 2,274 unrealized MTM Income (Loss)-Gas (399) 47 wholesale Gas 2.622 2.321 TOTAL WHOLESALE 10.988 9.297 310 132 442 7,834 DOMESTIC ELECTRICITY DELIVERY: Transmi ssi on Distribution TOTAL DOMESTIC ELECTRICITY DELIVERY OTHER INVESTMENTS 922 1,029 1,009 2.629 2,327 2.165 3.551 3,356 3,174 16 114 105 TOTAL REVENUES S14,5m 11.77 ,*Certain revenues in the wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.The level of electricity transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC s introduction of a greater degree of competition into the wholesale energy market A-5 I Ooeratina ExDenses Increase Changes in the components of operating expenses were as follows: Inc Fr Amour Fuel and Purchased Energy: Electricity $ 959 Gas 404 Maintenance and other operation 303 Non-recoverable Merger Costs (11)Asset Impairments 867 Depreciation and Amortization 134 Taxes other Than Income Taxes 51 Total:rease (Decrease) tom Previous Year 2002 200.(in millions)it % Amount %43.7 S(1,275)(36.7) 14.7 2,339 570.5 8.2 i (52.4)N.M.228 6.5 (182) (89.7)CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected, merger costs declined in 2001 and 2002 after the merger was consummated. In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling $1.4 billion (consisting of approximately, $866.6 million related to asset impairments, $321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included: 2002 Pre-Tax Estimated Loss (in millions)10.8 152 13.9 7.6 (16) (2.3)25.6 51.246 13.3 The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001. The return to service of the Cook Plants two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation. The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001.The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full years expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001.Maintenance and Other Operation expense rose in 2001 mainly as a result of additional traders incentive compensation and accruals for severance costs related to corporate restructuring. With the consummation of the merger with Asset Impairments Held for sale Asset Impairments Held and used Investment value Losses S 483.1 651.4 291.9 Total Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations. The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service.Depreciation and Amortization expense increased in 2001 primarily as a result of the A-6 commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and WestVirginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in Property, Plant and Equipment. Taxes OtherThan IncomeTaxes increased in 2002 due to a full year of state excise taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in Texas partly offset by the effect of Texas one-time 2001 assessments and decreased gross Texas receipts taxes due to deregulation. Interest. Preferred Stock Dividends, Minority Interest The decrease in Interest in 2002 was primarily due to a reduction in short-term interest rates and lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates offset in part by an increased amount of long-term debt outstanding. Interest expense decreased 15% in 2001 due to the effect of interest paid to the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.Minority Interest in Finance Subsidiary increased substantially in 2002 because the distributions to minority interest were in effect for the entire year. In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest. The minority interest was only in effect during the last four months of 2001.Other Income/Other Expenses This increase was primarily caused by an increase in equity earnings due to acquisitions of $63 million and a $73 million gain from the sale of a generating plant (see Note 1). Other Expenses increased by $110 million or 143%in 2001 due to costs to exit air transportation, fiber optic and Datapult businesses (see Note 1).Income Taxes The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book income offset by the tax effects of the sale of foreign operations. Although pre-tax book income increased considerably in 2001, Income Taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000.Extraordinary Losses and Cumulative Effect The loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change on January 1, 2002.In 2001 we recorded an extraordinary loss of$48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after-tax extraordinary loss of $35 million.New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark-to-market certain fuel supply contracts that qualify as financial derivatives. The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a Cumulative Effect of Accounting Change.Other Income increased by $110 million or 33% in 2002 due to the sale of AEP S retail electric providers in Texas and due to non-operational revenue (see Note 1). Other Expenses increased $134 million or 72% in 2002 due to non-operational expenses (see Note 1).Other Income increased $240 million in 2001.A-7 mI Discontinued Operations The operations shown below were discontinued or held for sale in 2002 (See Note 12). Results of operations including impairment losses, net of tax, of these businesses have been reclassified: Company 2002 2001 2000 (in millions)SEEBOARD 5 96 S 88 5 99 CitiPower (123) (6) 17 Pushan (7) 4 7 Eastex (156) -(1)90) 5 86 S12 Reclassification Balance sheet amounts have been restated to reflect our change in accounting policy regarding certain assets and liabilities related to forward physical and financial transactions (see "Reclassification discussion Note 1.)Based upon AEP s legal rights of offset, physical and financial contracts were netted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not netted in 1998 amounts as the impact is not material.A-8 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Operations (in millions -except per share amounts)Year Ended December 31.2002 2001 2000 REVENUES: wholesale Electricity S 8,366 S 6,976 $ 7,392 wholesale Gas 2,622 2,321 442 Domestic Electricity Delivery 3,551 3,356 3,174 other Investment 16 114 105 TOTAL REVENUES 14,555 12.767 11.113 EXPENSES: Fuel and Purchased Energy: Electricity 3,154 2,195 3,470 Gas 3.153 2,749 410 TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880 Maintenance and other operation 4,013 3,710 3,482 Non-recoverable Merger Costs 10 21 203 Asset Impairments 867 --Depreciation and Amortization 1,377 1,243 1,091 Taxes other Than Income Taxes 718 667 683 TOTAL EXPENSES 13.292 10,585 9,339 OPERATING INCOME 1,263 2,182 1,774 OTHER INCOME 445 335 95 LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 --LESS: OTHER EXPENSES 321 187 77 LESS: INTEREST 785 844 999 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 11 10 11 MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -INCOME BEFORE INCOME TAXES 235 1,463 782 INCOME TAXES 214 546 602 INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT 21 917 180 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122 EXTRAORDINARY LOSSES (NET OF TAX): DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION -(48) (35)LOSS ON REACQUIRED DEBT -(2) -CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -NET INCOME (LOSS) S 51) $ 971 $ 267 AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322 EARNINGS-(LOSS) PER SHARE: Income Before Discontinued operations, Extraordinary Items and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56 Discontinued Operations (0.57) 0.26 0.38 Extraordinary Losses -(0.16) (0.11)Cumulative Effect of Accounting change (1.06) 0.06 Earnings (Loss) Per share (Basic and Diluted) I$(1.5) L3.01 $ 0.83 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 J24 See Notes to Consolidated Financial Statements beginning on page L-1.A-9 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (in millions -except share data)December 31.2002 2001 ASSETS CURRENT ASSETS: Cash and cash Equivalents $ 1,213 $ 224 Accounts Receivable: customers 466 343 Miscellaneous 1,394 1,365 Allowance for uncollectible Accounts C119) (69)Fuel, Materials and Supplies 1,166 1,037 Energy Trading and Derivative Contracts 1,046 2,125 other 935 639 TOTAL CURRENT ASSETS 6,101 5,664 PROPERTY, PLANT AND EQUIPMENT: Electric: Production 17,031 17,054 Transmission 5,882 5,764 Distribution 9,573 9,309 Other (including gas and coal mining assets and nuclear fuel) 3,965 4,272 Construction work in Progress 1,406 1,015 Total Property, Plant and Equipment 37,857 37,414 Accumulated Depreciation and Amortization 16,173 15,310 NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104 REGULATORY ASSETS 2,688 3,162 SECURITIZED TRANSITION ASSETS 735 -INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633 ASSETS HELD FOR SALE 247 721 ASSETS OF DISCONTINUED OPERATIONS -3,954 GOODWILL 396 392 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795 OTHER ASSETS 1.783 1,872 TOTAL ASSETS $34,741 See Notes to Consolidated Financia1 Statements beginning on page L-1.A-10 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31, 2002 2001 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,042 S 1,914 short-term Debt 3,164 4,011 Long-term Debt Due within one Year* 1,633 1,095 Energy Trading and Derivative Contracts 1,147 1,877 other 1.804 1.924 TOTAL CURRENT LIABILITIES 9.790 10,821 LONG-TERM DEBT* 8.487V 8.410 EQUITY UNIT SENIOR NOTES 376 -LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603 DEFERRED INCOME TAXES 3.916 4.500 DEFERRED INVESTMENT TAX CREDITS 455 491 DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819 DEFERRED GAIN ON SALE AND LEASEBACK -ROCKPORT PLANT UNIT 2 185 194 OTHER NONCURRENT LIABILITIES 1.903 1.334 LIABILITIES HELD FOR SALE 91 87 LIABILITIES OF DISCONTINUED OPERATIONS -2.582 COMMITMENTS AND CONTINGENCIES (Note 9)CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH 321 321 SUBSIDIARIES MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 145 156 COMMON SHAREHOLDERS' EQUITY: Common Stock-Par value $6.50: 2002 2001 shares Authorized. .600,000,000 600,000,000 shares Issued. ...347,835,212 331,234,997 (8,999,992 shares were held in treasury at December 31, 2002 and 2001) 2,261 2,153 Paid-in Capital 3,413 2,906 Accumulated other Comprehensive Income (Loss) (609) (126)Retained Earnings 1,999 3,296 TOTAL COMMON SHAREHOLDERS' EQUITY 7.064 8,229 TOTAL LIABILITIES AND SHAREHOLDERS EQUITY $ $39297*See Accompanying schedules. See Notes to Consolidated Financial Statements beginning on page L-1.A-11 I AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated statements of cash Flows (in millions)Year Ended December 31.2002 2001 2000 OPERATING ACTIVITIES: Net Income (Loss) $ (519) S 971 $ 267 Plus: Discontinued operations 540 (86) (122)Net income from Continuing operations 21 885 145 Adjustments for Noncash Items: Asset Impairments, Investment value and other Impairments 1,188 --Depreciation and Amortization 1,403 1,277 1,152 Deferred Investment Tax Credits (31) (29) (36)Deferred Income Taxes (66) 157 (190)Amortization of operating Expenses and Carrying charges 40 40 48 cumulative Effect of Accounting Change (18) -Equity Earnings of Yorkshire Electricity Group plc -(44)Extraordinary Loss 50 35 Deferred costs under Fuel clause Mechanisms (31) 340 (449)Mark-to-Market of Energy Trading Contracts 263 (257) (170)Miscellaneous Accrued Expenses 30 (384) 217 changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (152) 1,766 (1,530)Fuel, Materials and Supplies (127) (78) 149 Accrued Revenues (283) 35 (71)Accounts Payable 52 (478) 1,292 Taxes Accrued (216) (147) 171 Payment of Disputed Tax and Interest Related to COLI --319 change in other Assets (177) (239) (283)change in other Liabilities (237) (161) 386 Net cash Flows From Operating Activities 1,677 2,759 1.141 INVESTING ACTIVITIES: Construction Expenditures (1,722) (1,654) (1,468)Purchase of Gas Pipe Line -(727) -Purchase of U.K. Generation -(943) -Purchase of coal Company -(101) -Purchase of Barging Operations -(266) -Purchase of wind Generation -(175) -Proceeds from Sale of Retail Electric Providers 146 --Proceeds from sale of Foreign Investments 1,117 383 -Proceeds from Sale of U.S. Generation -265 -other 37 (42) (18)Net Cash FlowS used For Investing Activities (422) (3.260) (1.486)FINANCING ACTIVITIES: Issuance of Common stock 656 11 14 Issuance of Minority Interest -744 -Issuance of Long-term Debt 2,893 2,863 878 Issuance of Equity unit Senior Notes 334 -Retirement of Cumulative Preferred stock (10) (5) (21)Retirement of Long-term Debt (2,514) (1,570) (1,303)change in short-term Debt (net) (829) (790) 1,328 Dividends Paid on Common stock (793) (773) (805)Dividends on Minority Interest in subsidiary -(5) -Net Cash Flows From (used for) Financing Activities (263) 475 91 Effect of Exchange Rate Changes on Cash (3) (1) 30 Net Increase (Decrease) in cash and cash Equivalents 989 (27) (224)cash and cash Equivalents from Continuing operations Beginning of Period 224 251 475 Cash and cash Equivalents from Continuing Operations -End of Period $L213 L 224 S 251.Net Increase (Decrease) in Cash and cash Equivalents from Discontinued operations $ (100) $ 17 $ (17)Cash and cash Equivalents from Discontinued operations Beginning of Period 108 91 108 Cash and Cash Equivalents from Discontinued operations End of Period $ 8A08 $ 91 See Notes to consolidated Financial Statements beginning on page L-1.A-12 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equitv and Comprehensive Income (in millions)DECEMBER 31, 1999 Issuances cash Dividends Declared Other comprehensive Income: Other Comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment Reclassification Adjustment For LOSS Included in Net Income Net Income Total Comprehensive Income DECEMBER 31, 2000 Issuances cash Dividends Declared other comprehensive Income: Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability Net Income Total Comprehensive Income DECEMBER 31, 2001 Issuances cash Dividends Declared Other Com prehensive Income: Other comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability unrealized Loss on securities Available For Sale Net Income (Loss)Total comprehensive Income DECEMBER 31, 2002 Common stock shares Amount 331 $2,149-3 331 331 17$2, 152 1$2,153 108 Paid-In Capi tal$2,898 11 6 S2,915 9 (18)S2,906 568 (61)S 3.13 Retained Earnings S3,630 (805)(2)267$3,090 (773)8 971$3,296 (793)15 (519)1S9M Accumulated other comprehensive Income (Loss)$ (4)(119)20 S (103)(14)(3)(6)S (126)117 (13)(585)(2)sff)Total$8,673 14 (805)4 7,886 (119)20 267 168$8,054 10 (773)(10)7,281 (14)(3)(6)971 948$8,229 676 (793)(4 )(163)117 (13)(585)(2)(519)(1.002)MA See Notes to Consolidated Financial statements beginning on page L-1.A-13 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31. 2002 Call Price per Shares Shares Amount (In share(a) Authorized(b) Outstandinatf) Millions)Not subject to Mandatory Redemption: 4.00% -5.00% S102-$110 1,525,903 608,150 $ 61 Subject to Mandatory Redemption: 5.90% -5.92% (c) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 51 Total subject to Mandatory Redemption (c) 84 Total Preferred stock 1145 December 31. 2001 Call Price per Shares shares Amount (In share(a) Authorized(b) Outstandino(f) Millions)Not subject to Mandatory Redemption: 4.00% -5.00% S102-S110 1,525,903 614,608 $ 61 subject to Mandatory Redemption: 5.90% -5.92% Cc) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 100,000 10 Total subject to Mandatory Redemption (c) 95 Total Preferred Stock S156 NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is S100 per share for all outstanding shares.(b) AS of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and 7,713,501 shares of $100,$25 and no par value preferred stock, respectively, that were authorized but unissued.(c) shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.(d) Not callable prior to 2003, after that the call price is $100 per share plus accrued dividends.(e) with sinking fund.(f) The number of shares of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares in 2001 and 209,563 shares in 2000.A-14 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries Maturity weighted Average Interest Rate December 31. 2002 Interest Rates 2002 at December 31.2001 December 31.2002 2001 (in millions)FIRST MORTGAGE BONDS (a)2002 -2004 2005 -2008 2022-2025 INSTALLMENT PURCHASE CONTRACTS (b)2002-2009 2011-2030 NOTES PAYABLE (c)2002-2021 SENIOR UNSECURED NOTES 2002 -2005 2006-2012 2032-2038 JUNIOR DEBENTURES 2025-2038 SECURITIZATION BONDS 2003-2016 OTHER LONG-TERM DEBT (d)Unamortized Discount (net)Total Long-term Debt outstanding Less Portion Due Within One Year Long-term Portion EQUITY UNIT SENIOR NOTES 2007 6.87%6.90%7.66%4.62%5.83%5.54%5.53%5.91%6.64%7.90%5.40%5.75%6.00%-7.85% 6.20%-8%6.875%-8.7% 3.75%-7.70% 1.35%-8.20% 3.732%-9.60% 2.12%-7.45% 4.31%-6.91% 6.00%-7-3/8% 7.60%-8.72% 6.00%-7.85% 6.20%-8%6-7/8%-8.80% 1.80%-7.70% 1.55%-8.20% 4.048%-9.60% 2.31%-7.45% 6.125%-6.91% 7.20%-7-3/8% 7.60%-8.72% $ 648 463 773 396 1,284 520 1,834 2,295 690 205 797 247 (32)10.120 1 633 S 1,246 699 850 446 1,234 217 1,910 1,727 340 618 258 (40)9, 505 1.095 L 8410 3.54%-6.25% 5.75%S-376 NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.(b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. variable rates generally relate to specified short-term interest rates.(d) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 9 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. Long-term debt outstanding at December 31, 2002 (includes Equity Unit senior Notes) is payable as follows: (in millions)2003 2004 2005 2006 2007 Later Years Unamortized Discount Total S 1,633 824 993 1, 611 1,081 4.386 10,528 32£10,9 A-15 AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Combined Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Goodwill and other Intangible Assets Merger Nuclear Plant Restart Rate Matters Effects of Regulation customer Choice and Industry Restructuring Commitments and contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans stock-Based compensation Business Segments Risk Management, Financial Instruments And Derivatives Income Taxes Basic and Diluted Earnings Per share Supplementary Information Power and Distribution Projects Leases Lines of credit and sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Minority Interest in Finance subsidiary Equity units Subsequent Events (unaudited) combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 5 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 15 Note 16 Note 17 Note 18 Note 19 Note 20 Note 21 Note 22 Note 23 Note 24 Note 25 Note 26 Note 27 Note 30 A-16 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted ouraudits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 3 to the consolidated financial statements, the Company adopted SFAS 142, 'Goodwill and Other Intangible Assets, effective January 1, 2002.As discussed in Note 13 to the consolidated financial statements, the Company recorded certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002./s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 A-17 L_MANAGEMENTS RESPONSIBILITY The management of American Electric Power Company, Inc. has prepared the financial statements and schedules herein and is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with accounting principles generally accepted in the United States of America, using informed estimates where appropriate, to reflect the Company s financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company s Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Companys established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP -independent auditors and the Companys internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the previous page.The auditors provide an objective, independent review as to management s discharge of its responsibilities insofar as they relate to the fairness of the Company s reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Companys internal control structure over financial reporting. A-18 AEP GENERATING COMPANY AEP GENERATING COMPANY Selected Financial Data INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant Year Ended December 31.2002 2001 2000 1999 1998 (in thousands) $213,281 $227,548 $228,516 $217,189 $224,146 207,152 220.571 220,092 211,849 215,415 6,129 6,977 8,424 5,340 8,731 3,681 3,484 3,429 3,659 3,364 2,258 2,586 3.869 2.804 3.149 ,$L52 $ 77875 $ ,94 $6J195 $ Ai December 31.2002 2001 2000 1999 1998 (in thousands) $652,213 358.174$648,254 337,151$-3-1-,10$642,302 315.566$36,736$640,093 295.065 ,$345,028$636,460 277. 855 Total Assets$349,729 $361,41 $374,602 A U $403 892 Common stock and Paid-in capital Retained Earnings Total Common shareholder's Equity$ 24,434 18.163$ 4259$ 24,434 13.76$ 3-8,19-5$ 24,434 9,722$ 30,235 3.673$ 36,235 2,770$ 900 Long-term Debt (a)Total Capitalization And Liabilities S_4i8QZ $4,793 $ 44,808 $ 48 44,79 UAJTZ9 $36 1 ,41 $374,602 $98 4 $403 1892 (a) Inc7uding portion due within one year.B-1 AEP GENERATING COMPANY Management s Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating Expenses Decrease Operating Expenses decreased 6% as follows: Operating Revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, l&M will purchase all of AEGCo's Rockport capacity unless it is sold to other utilities. A unit power agreement between AEGCo and KPCo expires in 2004.The KPCo unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. Results of Operations (dollars in thousands) ._ _ .._ ._ .., _ _ _ _ _ _ _ _ _Increase (Decrease) From Previous Year Amount %$(13,723) (13)1,899 17 565 6 137 1 Fuel other operation Maintenance Depreciation Taxes other Than Taxes Income Taxes Total Income (976)(1.321)S (3,41)(23)(46)(6)The decrease in Fuel expense reflects a decrease in generation and lower average fuel costs.Other Operation expense increased due to increased costs for employee benefits and property insurance. The increase in Maintenance expense can be attributed to shorter duration of maintenance outages for boiler inspection and repair in 2001.Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and personal property taxes reflecting a favorable change in the law which lowered the tax for Rockport Plant.Net Income decreased $323,000 or 4% as a result of limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant.The decrease in Income Taxes attributable to operations is primarily due to a decrease in pre-tax operating income and a change in estimate for state income tax accruals.Operating Revenues Decrease The decrease in Operating Revenues of$14,267,000 or 6% reflects a decrease in recoverable expenses, primarily fuel.B-2 AEP GENERATING COMPANY Statements of Income OPERATING REVENUES OPERATING EXPENSES: Fuel Rent -Rockport Plant Unit 2 other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Year Ended December 31.2002 2001 2000 (in thousands) $213.281 $227.548 $228,516 TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDITS INTEREST CHARGES NET INCOME 89,105 68,283 12,924 9,418 22,560 3,281 1.581 207,152 6,129 343 198 3,536 2.258.$ -752 102,828 68,283 11,025 8,853 22,423 4,257 2.902 220. 571 6,977 30 16 3,470 2.586$_zl875 102,978 68,283 10,295 9,616 22,162 3,854 2.904 220.092 8,424 6 17 3,440 3.869$ 7L984 Statements of Retained Earnings RETAINED EARNINGS JANUARY 1 NET INCOME CASH DIVIDENDS DECLARED RETAINED EARNINGS DECEMBER 31 See Notes to Financia7 Statements beginning on page L-1.Year Ended December 31.2002 2001 2000 (in thousands) $13,761 $ 9,722 $3,673 7,552 7,875 7,984 3 150 3.836 1.935 18&-63 $13 ,761 $4X7 B-3 AEP GENERATING COMPANY Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $637,095 $638,297 General 4,728 3,012 Construction work in Progress 10.390 6.945 Total Electric Utility Plant 652,213 648,254 Accumulated Depreciation 358,174 337.151 NET ELECTRIC UTILITY PLANT 294,039 311.103 OTHER PROPERTY AND INVESTMENTS 119 119 CURRENT ASSETS: cash and cash Equivalents -983 Accounts Receivable: Affiliated Companies 18,454 22,344 Miscellaneous -147 Fuel 20,260 15,243 Materials and supplies 4,913 4,480 Prepayments -244 TOTAL CURRENT ASSETS 43.627 43.441 REGULATORY ASSETS 4.970 5.207 DEFERRED CHARGES 6,974 1.471 TOTAL ASSETS S3A 4 29 $6134 see Notes to Financial Statements beginning on page L-1.B4 AEP GENERATING COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stock Par value $1,000: Authorized and outstanding 1,000 Shares $ 1,000 $ 1,000 Paid-in capital 23,434 23,434 Retained Earnings 18163 13761 Total Common shareholder s Equity 42,597 38,195 Long-term Debt 44.802 44,793 TOTAL CAPITALIZATION 87.399 82.988 OTHER NONCURRENT LIABILITIES 301 76 CURRENT LIABILITIES: Advances from Affiliates 28,034 32,049 Accounts Payable: General 26 7,582 Affiliated Companies 15,907 1,654 Taxes Accrued 2,327 4,777 Rent Accrued Rockport Plant Unit 2 4,963 4,963 other 1.111 3.48 TOTAL CURRENT LIABILITIES 52.368 54.506 DEFERRED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 111,046 116.617 REGULATORY LIABILITIES: Deferred Investment Tax credits 52,943 56,304 Amounts Due to Customers for Income Taxes 16.670 22.725 TOTAL REGULATORY LIABILITIES 69.613 79.029 DEFERRED INCOME TAXES 29.002 27,975 DEFERRED CREDITS -150 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES $349,729 $M1,341I See Notes to Financia7 statements beginning on page L-1.B-5 AEP GENERATING COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation Deferred Income Taxes Deferred Investment Tax Credits Amortization of Deferred Gain on sale and Leaseback -Rockport Plant Unit 2 Change in Certain Current Assets and Liabilities: Accounts Receivable Fuel, Materials and supplies Accounts Payable Taxes Accrued other Assets other Liabilities Net Cash Flows From operating Activities $ 7,552 S 7,875 $ 7,984 22,560 (5,028)(3,361)(5,571)4,037 (5,450)6,697 (2,450)(5,211)(2.295)11,480 22,423 (6,224)(3,414)(5,571)1,224 (4,738)(4, 597)(216)(569)(1.244)4,949 22,162 (5,842)(3,396)(5,571)1,392 6,486 (13,157)708 1,636 (404)11. 998 INVESTING ACTIVITIES Construction Expenditures FINANCING ACTIVITIES: Return of Capital to Parent Company change in short-term Debt (net)Change in Advances From Affiliates (net)Dividends Paid Net Cash Flows From (Used For)Financing Activities (5,298)(4,01-5)(3,150)(7.165)(6,868)3,981 (3.836)145 (5,190)(5,801)(24,700)28,068 (1.935)(4,368)Net Increase (Decrease) in cash and cash Equivalents Cash and cash Equivalents January 1 cash and cash Equivalents December 31 supplemental Disclosure: Cash Paid for interest net of capitalized amounts was and for income taxes was $7,884,000, $8,597,000 and respectively. (983)983$~ _(1,774)2,757$ 98 2,440 317$2,019,000, $1,509,000 and $3,531,000 $6,820,000 in 2002, 2001 and 2000, See Notes to Financial Statements beginning on page L-1.B-6 11, AEP GENERATING COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) COMMON STOCK EQUITY (a) $42.597 $38.195 LONG-TERM DEBT Installment Purchase Contracts City of Rockport (b)series Due Date 1995 A, 2025 (c) 22,500 22,500 1995 B, 2025 (c) 22,500 22,500 unamortized Discount (198) (207)TOTAL LONG-TERM DEBT 44.802 44,793 TOTAL CAPITALIZATION $87399 29 (a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There were no other material transactions affecting Common stock and Paid-in Capital in 2002, 2001 and 2000.(b) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant.(C) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006.See Notes to Financia 7 Statements beginning on page L-1.B-7 AEP GENERATING COMPANY Index to Combined Notes to Financial Statements The notes to AEGCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to AEGCo. The combined footnotes begin on page L-1.significant Accounting Policies Effects of Regulation Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 7 Note 9 Note 10 Note 11 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 B-8 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of AEP Generating Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 B-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES =AEP TEXAS CENTRAL COMPANY AND Selected Consolidated Financial Data SUBSIDIARIES 2002 Year Ended December 31.2001 2000 (in thousands) 1999 INCOME STATEMENTS DATA: operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements Gain (Loss) on Reacquired Preferred Stock$1,690,493 1.296.760 393,733 8,079 125.871 275,941 275,941$1,738,837 1,443.106 295,731 5,324 116.268 184,787 (2.509)182,278$1,770,402 1.463.304 307,098 7,235 124,766 189,567 189,567$1,482,475 1.188.490 293,985 8,113 114 380 187,718 (5 517)182,201 6,931 1998$1,406,117 1 123.330 282, 787 760 122.036 161,511 161,511 6,901 241 242 241 4 (2.763)Earnings Applicable To Common stock$_275704 1$_182L 06$ 172.507 L$_ 15-461Q Year Ended December 31.2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation And Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$5,625,736 2.405.492$320 -244$5'536P438 $ 187,898 (73,160)986.396$1- 1O1t 13A$ 5,942-2001$5,769,707 2.446.027$ 573,903 826,197$1,420QlQQ 2000 (in thousands) $5,592,444 2.297,189$ 573,904 792,219$ 5,951 1999$5,511,894 2.247,225$ 573,904 758.894-$-I 33-,79$5.95 1998$5,336,191 2.072.686$4,735,_ff $ 573,904 734. 387$1 1QWLZX CPL Obli ated, Mandatori 1y Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior subordinated Debentures of CPL Long-term Debt (a)Total capitalization And Liabilities $-13-6 Z 5-SI136 25Q$148,500$1,454,559 $154,5I41$5,467,01$4,735,656 (a) Including portion due within one year.C-1 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Managrement s Discussion and Analvsis of Results of Operations AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TCC s behalf byAEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TCC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TCC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TCC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC s sales as described below under"Results of Operations. In December 2002, AEP sold the affiliated REP to an unrelated third party who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP were classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income increased $94 million or 51 % primarily due to $262 million of revenues associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas which resulted in the loss of customers and reduced prices (see Note 8).In 2001, Income Before Extraordinary Item decreased $5 million or 3%, primarily resulting from a settlement of Texas municipal franchise fees and increased Maintenance expenses.Changes in Operating Revenues Increase (Decrease) From Previ ous Year (dollars in millions)2002 2001 Amount % Amount whol esal e El ectri ci ty*Energy Delivery*Sales to AEP S (1, 096.4) (90) S(29.9) (2)81.4 17 (5.6) (1)Affiliates 966.7 N.M. 4.0 11 Total 5(8.) (3) 5 31. 5) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful In 2002, Wholesale Electricity revenues decreased as a result of the elimination of TCCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins offset in part by the interchange cost reconstruction C-2 (ICR) adjustments (see Note 6). In 2001, the decrease in Wholesale Electricity revenues was primarily attributable to unfavorable wholesale power marketing and trading conditions. In 2002, Sales to AEP Affiliates revenue increased primarily due to increased revenues from the newly created affiliated REP.Although TCC sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue. Revenues for 2002 included $262 million of revenues, associated with recognition of stranded costs in Texas (see Note 8). Energy Delivery revenue also included revenues received for securitized assets beginning in 2002 (see Note 8).Chances in Operatinc ExDenses based on the current spot market price.Changes in natural gas prices affect TCC s fuel expense; however, they generally did not impact results of operations in 2001 and 2000 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.In 2002, the increase in Wholesale Electricity Purchased Power expense is due to higher MWH purchases from the market where we could purchase power at prices lowerthan our cost to produce. ICR adjustments also had the effect of increasing Wholesale Electricity Purchased Power expense and decreasing AEP Affiliates Purchased Power expense in 2002 (see Note 6).In 2001, Purchased Power increased overall largely due to higher natural gas prices.Although gas prices declined in 2001, they were higher during the first half of 2001 when TCC was making most of its purchases. In 2002, Other Operation expense decreased due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses.Increase (Decrease) From Previous Year A Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreci ati on And Amortization Taxes other Than Income Taxes Income Taxes Total V((dollars in millions) In 2002, Maintenance expense decreased 2002 2001 due to two scheduled '18 month interval mount % Amount % refueling outages for STP during 2001 that increased Maintenance expense above the:246.2) (50) SC58.8) C11) 2002 and 2000 levels. Also contributing to the decrease in 2002, and the increase in 83.5 65 C16.2) (11) 2001, was an increase in Maintenance 83.5* 65 (16.2) (l ) expense for scheduled major overhauls of (35.3) (60) 26.0 80 four power plants in 2001.(17.1) (5) 1.7 1-7 1 -I -tO'.i.) L.+/-+/-J +/-U. I IO In 2002, the increase in Depreciation and Amortization is attributable to the amortization 45.8 27 (10.4) (6) of regulatory assets that were securitized in 4. 6 5 14.4 19 the first quarter of 2002, offset by the 26.1 23 12.4 12 elimination of excess earnings expense in.46) (10) -A) C') 2002 under Texas Restructuring Legislation (see Note 8).la In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of fuel and decreased generation. The decrease in Fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. TCC used natural gas as fuel for 32% of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax, due to deregulation. In 2001, Taxes Other Than Income Taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees, and a new tax levied by the C-3 PUCT, the Texas System Benefit Fund Assessment. In 2002, the increase in Income Taxes is due to an increase in pre-tax income offset by changes in timing between book/tax accounting differences in state income taxes.In 2001 the increase in Income Tax expense is primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income.Other Changes In 2002, Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the energy related construction projects included in Nonoperating Income increased $34 million and $15 million in 2002 and 2001. The expenses associated with these projects included in Nonoperating Expenses increased$32 million and $14 million in 2002 and 2001.current cost to generate electricity, TCC proposed in September 2002 to "inactivate various, high-cost gas fired generating facilities. In the third quarter 2002, TCC recorded an impairment charge of approximately $95.6 million (pre-tax) related to these plants and recorded approximately $4.0 million (pre-tax) for severance charges.Both of these charges were deferred and recorded in RegulatoryAssets Designated for or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 8). In the fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional plant impairments, fuel inventory and materials and supplies, and an additional $1.5 million pre-tax charge was recorded related to severance charges (see Note 13) related to the Inactivated plants. The entire $23.1 million was also deferred and recorded in Regulatory Assets Designated for or Subject to Securitization. In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax non-operating income.In 2002, Interest Charges increased primarily due to higher levels of outstanding debt (see TCC s schedule of Long-term Debt and Consolidated Statements of Capitalization for further information). In 2001, the decrease in interest charges was attributable to lower average interest rates associated with short-term and long-term debt.Extraordinary Loss The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas.Impairment As a result of TCC s recent abilityto purchase electricity at a significantly lower price than its C-4 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP A ffiliates TOTAL OPERATING REVENUES$ 127,502 554,547 1.008.444 1.690.493 OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES 245,834 211,358 23,406 304,094 63,392 214,162 95,500 139.014 1. 296, 760$1,223,893 473,182 41.762 1. 738. 837 492,057 127,816 58,641 321,227 71,212 168,341 90,916 112.896 1.443.106$1,253,836 478,814 37.752 1.770.402 550,903 144,021 32,591 319,539 60,528 178,786 76,477 100.459 1.463. 304 OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)393,733 53,141 41,910 3,152 295,731 22,552 17,626 (398)307,098 5,830 3,668 (5,073)INTEREST CHARGES 125. 871 116.268 124,766 INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567 EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001)NET INCOME 275,941 (2.509)182,278 242 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS GAIN ON REACQUIRED PREFERRED STOCK 241 241 4 EARNINGS APPLICABLE TO COMMON STOCK$ -18Z-16 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 (in thousands) $182,278 2000$189,567 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME$275,941 (36)(73,124)$18 2- dl1 S1W2,WA The common stock of TCC is owned by a wholly owned subsidiary of AEP.See Notes to Financia7 statements beginning on page L-1.C-5 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31.2002 2001 2000 (in thousands) BEGINNING OF PERIOD $826,197 $792,219 $758,894 NET INCOME 275,941 182,278 189,567 DEDUCTIONS (ADDITIONS): Capital stock Gains (4) --Cash Dividends Declared: Common stock 115,505 148,057 156,000 Preferred stock 241 242 241 other -1 1 BALANCE AT END OF PERIOD 26 $ 6197 $792,219 The common stock of TCc is owned by a wholly owned subsidiary of AEP.see Notes to Financial statements beginning on page L-1.C-6 --AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Nuclear Fuel Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS SECURITIZED TRANSITION ASSETS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: General Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued Utility Revenues Energy Trading and Derivative Contracts Prepayments and other current Assets TOTAL CURRENT ASSETS REGULATORY ASSETS REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION NUCLEAR DECOMMISSIONING TRUST FUND DEFERRED CHARGES TOTAL ASSETS See Notes to Financial Statements beginning on page L-1.$2,903,942 698,964 1,296,731 258,386 200,947 266.766 5,625,736 2.405.492 3.220.244 3.977 734. 591 4.392 85,420 113,543 121,324 (346)32,563 51,593 27,150 22,493 2.133 455.873 458. 552 336.444 98.474 43,891 Sig56 E438$3,169,421 663,655 1,279,037 241,137 169,075 5,769,707 2.446,027 3. 323.680 47,950 28 039 10,909 38,459 6,249 (186)38,690 55,475 34,480 2.742 186 818 226. 812 959,294 98.600 21.837$4,9303 C-7 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock $25 Par Value: Authorized 12,000,000 shares outstanding 2,211,678 shares at December 31, 2002 6,755,535 shares at December 31, 2001 Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock CPL obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of CPL Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: short-term Debt Affiliates Long-term Debt Due within one Year Advances from Affiliates (net)Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$ 55,292 132,606 (73,160)986 396 1,101,134 5,942 136,250 1,209.434 2.452.760 74.572 650,000 229,131 126,711 72,199 36,242 666 24,791 51,205 19,811 36. 698 1.247.454 1.261.252 117.686 1,713 201.001 S5,356 A438$ 168,888 405,015 826.197 1,400,100 5,952 136,250 988.768 2,531.070 10.905 265,000 354,277 65,307 49,301 26,744 83,512 23,715 40,987 18,076 926.919 1,163.795 122.892 17,675 119.774$4 1 9,83A3D C-8 --l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income Adjustments to Reconcile Net Income to Net cash Flows from Operating Activities: Depreciation and Amortization Extraordinary Loss on Reacquired Debt Deferred Income Taxes Deferred Investment Tax credits Mark-toMarket Energy Trading and Derivative Contracts change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Interest Accrued Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission coordination Agreement settlement Texas wholesale Clawback (see Note 7)change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: Construction Expenditures Proceeds From Sales of Property and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: Issuance of Long-term Debt change in short-term Debt Affiliate (Net)Retirement of Common stock Retirement of Preferred stock Retirement of Long-term Debt change in Advances from Affiliates (net)special Deposit for Reacquisition of Long-term Debt Dividends Paid on Common stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities $275,941 $182,278 $189,567 214,162 113,655 (5,206)(1,558)(189,999)(4,899)27,490 (27,150)(6,167)(58,721)16,455 (262,000)(534)56.024 147.493 (151,645)143 (151. 502)797,335 650,000 (386,005)(6)(639,492)(227,566)(115, 505)(241)78.520 168,341 2,509 (72,568)(5,208)(12,048)52,862 (18,215)(2,502)(55, 311)27,986 179,866 10,767 11,163 469,920 (193,732)(354)(194.086)260,162 (475,606)84,565 (148,057)(242)(279,178)178,786 16,263 (5,207)8,191 (32,902)8,680 11,494 45,873 14,405 (96,872)15,519 589 12 .243 366,629 (199,484)(199.484)149,248 (151,440)(52,446)50,000 (156,000)(249)(160.887)Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1 Cash and cash Equivalents December 31 74,511 10.8909 (3,344)14.253 SLQ 3Q9 6,258 7.995 illw53 supplemental Disclosure: Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and for income taxes. was$95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and 2000,respectively. see Notes to Financial statements beginning on page L-1.C-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) S1.10o.134 S1.400.100 COMMON SHAREHOLDER S EQUITY (a)PREFERRED STOCK 3,035,000 authorized shares, 5100 par value Not Subject to Mandatory Redemption: call Price -December 31, Number of shares Redeemed series 2002 Year Ended December 31. Dec 2002 2001 2000 Shares outstanding
- ember 31. 2002 4.00% S105.75 100 --41,938 4,194 4.20% 103.75 ---17,476 1.748 Total Preferred stock 5.942 TRUST PREFERRED SECURITIES:
TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of TCC, 8.00%due April 30, 2037 136.250 LONG-TERM (See schedule of Long-term Debt): First Mortgage Bonds 152,353 Securitization Bonds (a) 796,635 Installment Purchase Contracts 489, 577 Senior unsecured Notes -Less Portion Due within One year (229.131)Long-term Debt Excluding Portion Due within one Year 1.209.434 TOTAL CAPITALIZATION (a) In February 2002, TCC issued securitization bonds. S386 million of the proceeds 4,543,857 shares of common stock.See Notes to Financial Statements beginning on page L-1.4,204 1,748 5.952 136. 2 50 614,200 489,568 150,000 (265.000)988. 768 was used to retire C-1 0 i -AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) December 31, 2002 2001 (in thousands) % Rate Due 7.25 2004 7.50 2002 6-7/8 2003 7-1/8 2008 7.50 2023 6-5/8 2005 Total October 1 December 1 February 1 February 1 April 1 July 1 S 27,400 16,418 18,581 17,996 71. 958$100,000 115,000 49,200 75,000 75,000 200 000 ikQu Q% Rate Due Matagorda County Navigation District, Texas: 6.00 2028 July 1 6-1/8 2030 May 1 3.75 2030(a) May 1 4.00 2030(a) May 1 4.55 2029(a) Nov .Guadalupe-Blanco River Authority District, Texas: (b) 2015 November 1 Red River Authority District, Texas:$120,265 60,000 111,700 50,000 100,635 S120,265 60,000 111,700 50,000 100,635 First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Securitization Bonds outstanding were as follows: 40,890 40,890 Final Payment Maturity Rate Date Date 3.54 1/15/2005 1/15/2007 5.01 1/15/2008 1/15/2010 5.56 1/15/2010 1/15/2012 5.96 7/15/2013 7/15/2015 6.25 1/15/2016 1/15/2017 unamortized Discount Total December 31.2002 2001 (i~nthousands) 6.00 2020 June 1 6,330 6,330 unamortized Discount (243) (252)Total S4O9,577 (a)installment Purchase contract provides for bonds to be tendered in 2003 for 3.75% and 4.00% series and in 2006 for 4.55% series.Therefore, these installment purchase contracts have been classified for payments in those years.(b) A floating interest rate is determined monthly. The rate on December 31, 2002 was 1.7%.Under the terms of the installment purchase contracts, TCC is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: S128,950 154,507 107,094 214,927 191,857 (700)5796>6i5$In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 2002 February 22 Cc)Total December 31.2002 2001 (in thousands) $ -S150.000 S -$150.AlOO (c) A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.56%.C-11 At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 229,131 75,951 121,937 152,900 52,729 806.860 1,439,508 (943)51,438,56 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of TCC.C-12 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to TCC s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to TCC. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Merger Rate Matters Effects of Regulation customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Asset Impairment and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 C-1 3 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas Central Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Companyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31,2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 C-14 -J al AEP TEXAS NORTH COMPANY AEP TEXAS NORTH COMPANY Selected Financial Data 2002 Year Ended December 2001 2000 (in thousands) 31 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income (Loss) Before Extraordinary Item Extraordinary Loss Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$ 450,740 442.869 7,871 (703)20,6845 (13,677)(13,677)104$556,458 523.068 33,390 2,195 23, 275 12,310 12,310 104$571,064 518.723 52,341 (1,675)23,216 27,450 27,450 104 1999$445,709 391.910 53,799 2,488 24,420 31,867 (5.461)26,406 104 1998$424,953 365,677 59,276 2,712 24.263 37,725 37,725 104$ 37,621$ (13.781)S 34-6 S 26,302 2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric utility Plant Total Assets Common stock and Paid-in Capital Accumulated other Comprehensive Income (LosS)Retained Earnings Total Common Shareholder's Equity$1,201,747 521.792 S 679,955$ 877,175$ 139,565 (30,763)71.942$1&80,744 2001$1,260,872 546,162$ 714,710$ 139,565 105.970$_241S53-5 December 31.2000 (in thousands) $1,229,339 515,041$ 714,298 51,087. 504$ 139,565 122,588$_262 153 1999$1,182,544 495.847 5 686,697$ 861,205$ 139,565 113,242 S_252 s807 1998$1,146,582 473.503$ 673,079$,819,446 S 139,565 114.940 S 254,505 Cumulative Preferred stock: Not subject to Mandatory Redemption S 2,367 Long-term Debt (a) $ 132,50 Total Capitalization And Liabilities S 877L21Z5 S 255,967 255.7$S_22 _N S 6 8 L&6t4875 S1.087.iOA 5 8612,05 S _819A446 (a) Including portion due within one year.D-1 AEP TEXAS NORTH COMPANY Manaaement s Narrative Analysis of Results of ODerations AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TNC s behalf byAEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TNC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TNC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TNC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC s sales as described below under"Results of Operations. In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale, during 2002, sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP will be classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income decreased $26.0 million or 211 % primarily due to a $38.1 million long-lived asset impairment charge ($24.8 million net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a$4.7 million impairment charge ($3.1 million net of tax) related to the abandonment of a wind-powered generation facility (see Note 13).Changes in Operatina Revenues Increase (Decrease) From Previous Year (in millions) h wholesale Electricity* Energy Delivery*sales to AEP S(231. 7)(95.7)(63)(57)Affiliates 221.7 N.M.Total ()05.7) (19)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful Wholesale Electricity revenues decreased as a result of the elimination of TNCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins, partially offset by the ICR adjustments (see Note 6).D-2 Sales to AEP Affiliates increased primarily due to increased revenues from the newly created affiliated REP. Although TNC sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue.Changes in Operating Expenses Increase (Decrease) From Previous Year (in millions) %Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total S(76.7)10.0 (19 .1)(6.3)42.9 (7.1)(5.8)(18.1)gun 2)(43)14 (34)(6)N.M.(14)(21)N.M.(15)electricity at a significantly lower price than its current cost to generate electricity, TNC proposed in September 2002 to Inactivate various, high-cost gas fired generating facilities. TNC recorded an impairment charge in the third quarter 2002 of approximately $34.2 million related to these plants, which was recorded in Asset Impairments expense. In the fourth quarter 2002, an additional asset impairments charge of $3.9 million was also recorded in connection with these plants, along with a$4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, a $1.2 million charge associated with fuel inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (recorded in Other Operations) was recorded in the fourth quarter of 2002 related to the"inactivated plants.Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation and the elimination of regulatory asset amortization that ended in 2001.The decrease in Taxes Other Than Income Taxes is primarily a result of one time 2001 assessments and a decrease in the gross receipts tax due to deregulation. The decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the impairment of various generating facilities. Other Changes Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the aforementioned energy related construction projects included in Nonoperating Income increased $45.5 million in 2002. The expenses associated with these projects included in Nonoperating Expenses increased $43.0 million in 2002.Interest Charges declined primarily due to lower interest rates.N.M. = Not Meaningful Fuel expense decreased due to a decrease in the average unit cost of fuel and decreased generation required due to decreased energy sales. TNC used natural gas as fuel for 42%of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect TNC s fuel expense;however, they generally did not impact results of operations in 2001 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.The net decline in total Purchased Power expense in 2002 was mainly due to both reduced MWHs purchased and reduced prices, partially offset by ICR adjustments (see Note 6).Other Operation expense decreased slightly in 2002 due to lower factoring and transmission expenses, offset in part by a$1.4 million write-down of material and supply inventory associated with the impaired plants.As a result of TNC s recent ability to purchase D-3 it, AEP TEXAS NORTH COMPANY Statements of Operations Year Ended December 31, 2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Tax Expense (Credit)TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDIT INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$136,962 73,353 240,425 450.740 100,466 80,391 37,582 104,960 42,898 22,295 43,620 22,471 (11.814)442.869 7,871 53,763 54,755 (289)20.845 (13,677)104 2001 (in thousands) $368,741 169,036 18.681 556.458 177,140 70,395 56,656 111,248 22,343 50,705 28,319 16.262 523.068 33,390 12,199 10,695 (691)23.275 12,310 104> t12 20l6$376,206 176,204 18,654 571,064 183,154 68,080 57,773 93,078 21,241 55,172 25,321 14,904 518.723 52,341 9,530 12,664 (1,459)23.216 27,450 104$ 27,3A6 2000 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) $(13,677) $12,310 $27,450 NET INCOME (LOSS)OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(15)-(30.74)i$12 1 3i The common stock of TNC is owned by a wholly owned subsidiary of AEP.see notes to Financial statements beginning on page L-1.D-4 AEP TEXAS NORTH COMPANY Statements of Retained Eaminqs Year Em 2002 (in BEGINNING OF PERIOD $105,970 i NET INCOME (LOSS) (13,677)DEDUCTIONS: cash Dividends Declared: Common Stock 20,247 Preferred stock 104 BALANCE AT END OF PERIOD 7192A2 The common stock of TNC is owned by a who77y owned subsidiary of AEP.see notes to Financial Statements beginning on page L-1.Jed December 31.2001 2000 thousands)
- 122,588 $113,242 12,310 27,450 28,824 104$1I0,7=0 18,000 104 D-5 AEP TEXAS NORTH COMPANY Balance Sheets December 31, 2002 2001 (in thousands)
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Allowance for Uncollectible Accounts Fuel Inventory Materials and Supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS See Notes to Financia7 Statements beginning on page L-1.$ 353,087 254,483 445,486 111,679 37.012 1,201,747 521.792 679 955 1,213 2.248 1,219 62,660 43,632 (5,041)12,677 9,574 6,829 4,130 1,070 136.750 45,097 11 912$877.175$ 443,508 250,023 431,969 112,797 22.575 1,260,872 546.162 714,710 24.933* 8.327 2,454 18,720 8,656 (196)8,307 11,190 10,240 966 60,337 54,122 2.446_$_8_64,875 D-6 AEP TEXAS NORTH COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock $25 Par value: Authorized 7,800,000 Shares outstanding 5,488,560 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred Stock Not subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: short-term Debt Affiliates Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES see Notes to Financia7 statements beginning on page L-1.$137,214 2,351 (30,763)71.942 180,744 2,367 132. 500 28, 861 125,000 80,407 32,714 76,217 117 3,697 2,776 3,801 17.414 342,143 117, 521 21.510 557 50,972$137, 214 2,351 105.970 245,535 2,367 220,967 468.869 6,296 35,000 50,448 33,782 11,388 4,191 17,358 4,762 12,402 9. 824 179 155 145.049 22,781 52 250 37.475$87,17 D-7 AEP TEXAS NORTH COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income (Loss)Adjustments to Reconcile Net Income to Net Cash Flows From operating Activities: Depreciation and Amortization writedown of Utility Assets writedown of wind Farm Assets Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: Construction Expenditures sales Proceeds and other Net Cash used For Investing Activities FINANCING ACTIVITIES: Retirement of Long-term Debt change in short-term Debt Affiliated (net)Change in Advances from Affiliates (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net Cash Flows From (used For) Financing Activities $(13,677) $ 12,310 $ 27,450 43,620 38,154 4,744 (12,275)(1,271)(1,127)(74,071)(2,754)(6,829)63,761 (13,661)14,169 (16,928)16, 514 38. 369 (43,563)150 (43,413)50,705 (11,891)(1,271)(3,506)24,844 3,187 (42,604)(1,543)32,505 (1,432)11,056 72. 360 (39,662)(127)(39.789)55,172 8,164 (1,271)2,590 (1,445)8,478 28,393 6,443 (53,841)15,465 2,549 (3.869)94,278 (64,477)(64,477)(130,799)125,000 29,959 (20,247)(104)3 809 (8,130)(28,824)(104)(37,058)(48,000)37,170 (18,000)(104)(28.934)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents at Beginning of Period Cash and cash Equivalents at End of Period (1,235)2,454$-1,2-19 (4,487)6.941 i__2,54 867 6.074 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $19,934,000 $19,279,000 and$19,088,000 and for income taxes was $15,544,000, $21,997,000 and ($906,000) in 2002, 2001 and 2000 respectively. see Notes to Financia7 statements beginning on page L-1.D-8 AEP TEXAS NORTH COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) $180.744 S245.535 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 810,000 Call Price December 31, Number of Shares Redeemed Series 2002 Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption: 4.40% $107 --1 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 Statements beginning on page L-1.shares outstanding December 31. 2002 23,672 2,367 2,367 88,190 44,310 132. 500 211,657 44,310 (35 000)220.967 D-9 AEP TEXAS NORTH COMPANY Schedule of LonQ-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousaniis-Y % Rate Due 6-7/8 2002 October 1 S -7 2004 October 1 18,469 6-1/8 2004 February 1 24,036 6-3/8 2005 October 1 37,609 7-3/4 2007 June 1 8,151 unamortized Discount (75)Q8 S 35,000 40,000 40,000 72,000 25,000 (343)i2IL-6S Under the terms of the installment purchase contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) 2003 $ -2004 42,505 2005 37,609 2006 -2007 8,151 Later Years 44 310 Principal Amount 132,575 Less: unamortized Discount C75)Total S First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due Red River Authority of Texas: 6.00 2020 June 1 December 31.2002 2001 (in thousands) 544310 S44,31 D-10 AEP TEXAS NORTH COMPANY Index to Combined Notes to Financial Statements The notes to TNC s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to TNC. The combined footnotes begin on page L-1.Combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued operations Note 12 Asset Imapairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of credit and Sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Jointly owned Electric utility Plant Note 28 Related Party Transactions Note 29 D-11 i INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas North Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 D-1 2 APPALACHIAN POWER COMPANY AND SUBSIDIARIES I APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data I .n" 11 IdnIA IJ .IIU 1* J.1 ... I -.----2002 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Gain Net Income Preferred stock Dividend Requirements Earnings Applicable to common Stock$1,814,470 1,512,407 302,063 20,106 116.677 205,492 205,492 2.897$ 202,195 2001$1,784,259 1.509.273 274,986 6,868 120,036 161,818 161,818 2.011$ 159&0QZ 2000 (in thousands) $1,759,253 1.558.099 201,154 11,752 148.000 64,906 8.938 73,844 2,504 1999$1,586,050 1,344,814 241,236 8,096 128.840 120,492 120,492 2.706 1998$1,672,244 1.443.701 228, 543 (8,301)126.912 93,330 93,330 2.497 December 31, 2002 2001 2000 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant 1999$5,262,951 2.079.490$5,895,303 2.424.607$5,664,657
- 2. 296. 481$5,418,278
- 2. 188. 796 3229 ,482$6.522 l 9S 1998$5,087,359 1.,984. 856 SI-1MA61 14.35Z2 Total Assets Common Stock and Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Total Cumulative Preferred Stock_4 &62.7 847 V4,047,038
$ 977,700 (72,082)260,439 ,166 Q5Z$ 976,244 (340)150, 797 I 1,12-6 7 0-$ 975,676 120, 584$1.,096,260Q $ 974,717 175. 854$ 924,091 179.461$103A52$ 17,790 $ 17,790 10.860 10,860$ 17,790 10,860$ 28.650$1,605,818 $ 18,491 20,310$1__3 Oi t1<6 65,$ 19,359 22.310 Long-term Debt (a)obligations under Capital Leases (a)Total Capitalization And Liabilities IL,55-6-55-9 _$It55L455 Si__5d751z L-3i,5&89 t{A,621T4~ $ 46,281$ 64,645$4Z482,78$65 57255$4I,Q4ZQ38 (a) Including portion due within one year.E-1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operation APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 retail customers in southwestern Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. APCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs.The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs.Results of Operations Net Income increased $44 million or 27% in 2002 due to higher retail sales resulting from increased generation, weather related electricity demands and reductions in Maintenance expense. Most significantly, the Mountainer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased $10 million as a result of a reduction in trading incentive compensation recorded in Nonoperating Expenses offset in part by decreased power trading gains recorded in Nonoperating Income.Net Income increased $88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000.In February 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in net income was growth in and strong performance by the wholesale electricity business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales.Operating Revenues Operating Revenues increased $30 million or 2% in 2002 as a result of weather related demand and increased generation resulting from availablility of plants previously down for maintenance coming back online. An increase of $25 million, or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power Pool transactions. Changes in components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions)2002 2001 Amount % Amount %$16.0 2 S(11.7) (1)(1.0) -20.1 3 wholesale El ectri ci ty*Energy Delivery*Sales to AEP Affiliates Total Revenues 15.2 5302 9 2 16.6 L25 0 11 1*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Operating Revenues for 2002 increased as a result of an increase in generation and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in residential and commercial sales due to warmer weather during July and September. Sales to AEP affiliates increased for the year due to an E-2 increase in generation capacity and power available to be delivered to AEP Power Pool.These increases were partially offset by flat industrial sales as recessionary conditions continued into 2002.The year 2001 saw a decrease in kilowatt hour sales to industrial customers. This decrease was due to the economic recession. In the fourth quarter, sales to residential and commercial customers declined, reflecting recession-related reductions in demand.The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP Power Pool transactions. As the quantity of energy sold by the AEP Power Pool rose, APCo s contribution of energy to the Pool rose, accounting for the increase in APCo s revenues from Sales to AEP Affiliates. Operating Expenses Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Power expenses were offset by decreases in power purchases from AEP Affiliates due to increases in APCo generation and availability as plants previously down for maintenance resumed operations. The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity purchased power expense and depreciation and amortization expenses.Changes in the components of Operating Expenses are as follows: Increase (Decrease) From Previous Year (dolTlars in millions)2002 2001 Amount % Amount %Fuel S 79.4 23 S (17.6) (5)of an increase in APCo generation. Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability in 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. Wholesale Electricity Purchases increased for 2002 as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. Electricity purchased power expense increased in 2001 due to increases in wholesale electricity prices and as a result of the previously mentioned plant outages.The decrease for 2002 in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability. Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo s MLR.Other Operation expense increased in 2002 mainly due to severance expenses related to the sustained earnings initiative plan, a reduction in the gains recorded on the dispositions of S02 emission allowances, and increased insurance premiums and other employee benefit costs. These increases were offset by reduced trading overhead expenses as a result of reduced staffing and weaker market conditions; a decrease in transmission equalization charges caused by a reduction in APCo s MLR ratio; and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. Additionally, the decrease was the result of a gain recorded on the disposition of S02 emission allowances offset in part by increased wholesale power trading incentive compensation expense.The decrease in Maintenance expense in 2002 is primarily due to previously discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in the year 2001.wholesale Electricity Purchases 15.0 36 AEP Affiliate Purchases (112.3) (32)other operation 8.9 3 Maintenance (10.2) (8)Depreciation and Amortization 8.9 5 Taxes other Than Income Taxes (4.6) (5)Income Taxes 18.0 19 Total __3.1 -17.4 70 (8.9) (3)(18.6) (7)7.9 -6 17.3 11 (11.8)(34. 5)(11)(27)(3)Fuel expense increased for 2002 as a result E-3 Depreciation and Amortization expense increased during 2002 due to increased amortization for the net generation-related regulatory assets related to the Companys West Virginia jurisdiction which were assigned to the distribution portion of the Companys business and are being recovered through regulated rates. Investment in production plant in service, primarily equipment related to emission control, contributed to the increase in depreciation and amortization expense.Depreciation and Amortization expense increased in 2001 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets in the Virginia and West Virginia jurisdictions. Additional investments in distribution and transmission plant also contributed to the increases in depreciation and amortization expense in 2001. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were assigned to the energy delivery businesss regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates.trading gains driven by a decline in market prices. Nonoperating Expenses decreased as a result of decreased trading incentives. The increase in Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable increases in the level of activity in the wholesale business s trading transactions outside of the AEP System s traditional marketing area.Interest Charges Interest Charges for 2002 decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000.The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily to a decrease in municipal license tax. The municipal license tax was replaced by the Virginia consumption tax. The municipal license tax was imposed on APCo and the Virginia consumption tax is imposed on the customer with APCo acting as collector agent.The decrease in Taxes Other Than Income Taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state.The increase in Income Taxes for 2002 was due to an increase in pre-tax income. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income.Nonoperating Income and Nonoperating Expenses The Nonoperating Income decrease for 2002 was due primarily to a decrease in net power E-4 '!APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates Total Operating Revenues OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total operating Expenses OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (BENEFIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY GAIN DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS $1,'1.Year Ended December 3 2002 2001 (in thousands) )33,904 $1,017,938 594,089 595,036 186.477 171,285 314.470 1.784.259 430,963 57,091 234,597 269,426 122,209 189,335 95,249 113.537 1,512.407 302,063 29,278 11,783 (2,611)116.677 205,492 205,492 2.897 L.351,557 42,092 346,878 260,518 132,373 180,393 99,878 95. 584 1,509.273 274,986 49,507 41,500 1,139 120.036 161,818 161,818 2.011 2000$1,029,657 574,918 154.678 1.759.253 369,161 24,720 355,774 279,114 124,493 163,089 111,692 130.056 1.558.099 201,154 31,204 16,329 3,123 148.000 64,906 8.938 73,844 2.504 EARNINGS APPLICABLE TO COMMON STOCK-$ZLn-A0 Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME $205,492 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge (1,580)Minimum Pension Liability (70,162)COMPREHENSIVE INCOME $13,50 see Notes to Financia7 Statements beginning on page L-1.$161,818 $73,844 (340)S161,AI A E-5 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31.2002 2001 2000 (in thousands) $150,797 $120,584 $175,854 205.492 161,818 73,844 356.289 282.402 249,698 Retained Earnings January 1 Net Income Deductions: cash Dividends Declared: Common stock Cumulative Preferred Stock: 4-1/2% series 5.90% Series 5.92% Series 6.85% series Total cash Dividends Declared capital Stock Expense Total Deductions Retained Earnings December 31 See Notes to Financia7 Statements beginning on page L-1.92,952 801 278 364 94,395 1.455 95.850$260,4139-129, 594 801 278 364 131,037 568 131.605$150, 797 126,612 811 307 364 289 128,383 731 129.114 E-6 --APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmi ssion Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and cash Equivalents Accounts Receivable: Customers Affiliated Companies Mi scellaneous Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial Statements beginning on page L-1.$2,245,945 1,218,108 1,951,804 272,901 206.54 5 5 ,895,303 2,424.607 3,470.696 54.653 115,748 4,285 132,266 122,665 28, 629 (13,439)53,646 59,886 30,948 94,238 13.396 526.,520 395.,553 64. 677$2,093,532 1,222,226 1,887,020 257,957 203,922 5, 664 ,657 2. 296. 48.3. 368. 176 53. 736 119,638 13,663 113,371 63,368 11,847 (1,877)56,699 59,849 30,907 137,742 16.018 501.587 397. 383 42, 265 E-7 APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock No Par value: Authorized 30,000,000 shares outstanding 13,499,500 Shares Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareowner s Equity Cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Taxes Accrued Customer Deposits Interest Accrued Energy Trading and Derivative Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.$ 260,458 717,242 (72,082)260.439 1,166,057 17,790 10,860 1,738,854 2,933,561 173.438 155,007 39,205 141,546 98,374 29,181 26,186 22,437 69,001 79. 832 660.769 701.801 33.691 44.517 80,070$4,62L,847 $ 260,458 715,786 (340)150.797 1,126,701 17,790 10,860 1.476. 552 2.631.903 84,104 80,007 291,817 127,597 84,518 55,583 13,177 21,770 121,161 79.089 874.719 703. 575 38,328 60. 518 89, 638 A4-82, 25 E-8 APPALACHIAN POWER COMPANY AND SUBSIDIARIES consolidated Statements of Cash Flows Year Ended December 2002 2001 (in thousands) 31.2000 OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Power Supply Costs (net)Mark-to-Market of Energy Trading Contracts Provision for Rate Refunds Extraordinary Gain Change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Revenue Refunds Accrued Incentive Plan Accrued Disputed Tax and Interest Related to COLI change in operating Reserves Rate Stabilization Deferral change in other Assets change in other Liabilities Net Cash Flows From Operating Activities INVESTING ACTIVITIES: Construction Expenditures Proceeds From sales of Property and other Net Cost of Removal and Other Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: Issuance of Long-term Debt Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Change in Advances From Affiliates Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net cash Flows used For Financing Activities $ 205,492 189,335 16,777 (4,637)6,365 (21, 151)(83,412)3,016 (41)27,805 (26,402)(858)(3,190)(43,337)14,948 280,710$ 161,818 180, 505 42,498 (4,765)1,411 (68,254)134,099 (19,957)35,592 (45,073)(7,675)(2,451)(5,358)19,418 (27.954)393. 854$ 73,844 163,202 8,602 (4,915)(84,408)(1,843)(4,818)(8,938)(166,911)18,487 (13,081)159,369 14,220 181 10,662 72,440 (19,770)75,601 (13,021)9.817 288. 720 (276, 549)1,074 (275.475)647,401 (315,007)(252,612)(92,952)(1.443)(14,613)(306,046)1,182 (8.434)(313.298)124,588 (175,000)(191,495)300,204 (129,594)(1.443)(72.740)(199,285)159 (7.500)(206. 626)74,788 (9,924)(136,166)68,015 (8,387)(126,612)(1.938)(140,224)Net Increase (Decrease) in cash and Cash cash and cash Equivalents January 1 cash and cash Equivalents December 31 Equivalents (9,378)13.663$ 4,285 7,816 5 $ 847 (58,130)63.977$ A Z supplemental Disclosure: Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000 and$124,579,000 and for income taxes was $125,120,000, $56,981,000 and $63,682,000 in 2002, 2001 and 2000, respectively. There were no noncash acquisitions under capital leases in 2002. In 2001 and 2000, non cash acquisitions under capital leases were $2,510,000 and $14,116,000, respectively. see Notes to Financia7 Statements beginning on page L-1.E-9 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) S1.166.057 $1.126.701 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: No par value -authorized shares 8,000,000 call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption (b): 4-1/2% $110 6 -7,011 subject to Mandatory Redemption (b): 5.90% cc) --10,000 5.92% Cc) _ _ -shares Outstanding December 31. 2002 177,899 47,100 61, 500 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Junior Debentures other Long-term Debt Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 17.790 4,710 6.150 10.860 489,697 235,027 1,166,609 2,528 (155.007)1.738.854 17.790 4,710 6.150 10.860 639,365 234,904 518,247 161, 507 2,536 (80.007)1.476.552 52,631,903 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.(b) The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date.(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90%series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirement. see Notes to Financial statements beginning on page L-1.E-1 0 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 7.38 2002 7.40 2002 6.65 2003 6.85 2003 6.00 2003 7.70 2004 7.85 2004 8.00 2005 6.89 2005 6.80 2006 8.50 2022 7.80 2023 7.15 2023 7.125 2024 8.00 2025 unamortized Total August 15 '-December 1-May 1-June 1-November 1-September 1-November 1-May 1-June 22-March 1-December 1-May 1-November 1-May 1-June 1 Discount S -30,000 21,000 50,000 50,000 30,000 100,000 70,000 30,237 20,000 45,000 45,000-1C 540)$ 50,000 30,000 40,000 30,000 30,000 21,000 50,000 50,000 30,000 100,000 70,000 30, 237 20,000 45,000 45,000 (1.872)M69,36 Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands) First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. X Rate Due (a) 2003 August 20 S 125,000 5125,00 7.45 2004 -November 1 50,000 50,00 4.80 2005 June 15 450,000 -4.32 2007 November 12 200,000 -6.60 2009 -May 1 150,000 150,00 7.20 2038 -March 31 100,000 100,00 7.30 2038 -June 30 100,000 100,00 unamortized Discount 8 391 6.75 Total VIA609 S51,2 (a) A floating interest rate is determined monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, respectively. 0 0 0 0 0 z Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds, by governmental authorities as follows: December 31.2002 2001 (in thousands) % Rate Due Industrial Development Authority of Russell county, Virginia: Junior debentures outstanding were as follows: December 31.2002 2001 (in thousands) 8-1/4% Series A due 2026 September 30 8% Series B due 2027-March 31 unamortized Discount Total S -S 75,000 90,000 (3 .493)U161, 50 7.70 2007 -November 1 S 17, 500 5.00 2021 -November 1 19,500 Putnam County, West Virginia: S 17, 500 19, 500 At December 31, 2002, future annual long-term debt payments are as follows: 5.45 2019 -June 1 41 6.60 2019 -July 1 3 Mason County, West Virginia: 7-7/8 2013 -November 1 1 6.85 2022 -June 1 4 6.60 2022 -October 1 5 6.05 2024 -December 1 3 unamortized Discount Total 0,000 40,000 0,000 30,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 155,007 121,008 530,010 100,011 217,513 782. 216 1,905,765 (11,904)0,000 0,000 0,000 0,000 1. 973)10,000 40,000 50,000 30,000 (2 096)1234.90A E-1 1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to APCO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to APCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investments Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note Note Note Note Note Note Note 17 18 20 22 23 24 29 E-1 2 INDEPENDENTAAUDITORS REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian PowerCompanyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance aboutwhetherthe financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 E-1 3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable to common Stock$1,400,160 1180T3 81 219,779 15,263 53. 869 181,173 181,173$1,350,319 1.098.142 252,177 7,738 68.015 191,900 (30.024)161,876$1,304,409 1.108.532 195,877 5,153 80,828 120,202 (25. 236)94,966$1,190,997 968.207 222,790 2,709 75. 229 150,270 150,270 2.131$18 139$1,187,745 975, 534 212,211 (1,343)77.824 133,044 133,044 2.131£ 410Q9f 1.095$ 160.781£__1798JA1 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$3,467,626 1.465.174£2_Q02 ,452$Z,153,240 $3,354,320 1.377.032$1,977,288 3$Z.2 "388$3,266,794 1.299.697$3,151,619 1.210.994£1,40,625$ &08Q8123$3,053,565 1.134. 348$1,912,=21 _$13 X&ZL42i Common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$ 616,410 (59,357)290.611$_847 7 604$ 615,395 176.103=$ 191 9,AH$ 614,380 99.069$ 713,449$ 613,899 246, 584$860.,483$ 613,518 186.441$Z 79R9,9 cumulative Preferred stock -subject to Mandatory Redemption (a)Long-term Debt (a)Obligations under Capital Leases (a)Total Capitalization and Liabilities L$ L6 1 Q6Z R 2$ i_ 4 Q$L 72293&$ 252i0f$L 25,000$ _ 9 2 4 .5 4 5 L Z &S 4_0ZZ0 L A42L3Z$3,87,491 (a) Including portion due within one year.F-1 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Manaaement s Narrative Analysis of Results of ODerations Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 689,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. CSPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each companies percentage share of AEP Power Pool revenues and costs.Results of Operations Net Income increased $19 million or 12% in 2002 due to reduced interest charges and a$30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio excise taxes stranded by Ohio deregulation offset by higher operating expenses.Operating Revenues Operating Revenues increased in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were: Increase (Decrease) From Previous Year (dollars in millions)Amount %Retail* S51 8 wholesale Marketing 3 2 unrealized MTM (4) (22)Other 1 3 wholesale Electricity* 51 6 Energy Delivery* 9 2 Sales to AEP Affiliates (10) (15)Total Revenues $5Q 4* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 35%. For the fall season, heating degree days increased 34%. This reflects a return to more normal weather conditions since the weather experienced in 2001 was abnormally mild.Operating Expenses Operating Expenses increased in 2002 mainly as a result of purchased power, operating expenses and state taxes.Changes in the components of Operating Expenses were: Increase (Decrease) From Previous Year (dollars in millions)Amount X Fuel wholesale Purchased Power AEP Affiliates Purchased Power other operation Expenses Maintenance Expense Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total$10 4 18 18 (2)4 25 5 6 37 6 8 (4)3 22 5 7 10%by a coal Fuel cost increased as a result of a increase in generation partially offset slight cost decrease per ton of consumed.Wholesale Purchased Power increased in 2002 due to increased purchases from third F-2 parties for resale to wholesale customers and to meet internal demand.Expenses related to AEP Affiliates Purchased Power increased due to greater system pool capacity charges.The increase in Other Operation expenses was attributable to a number of factors: higher OPEB post retirement costs as a result of higher medical cost and lower investment performance, 2002 Sustained Earnings Initiative Expenses, and the 2001 reversal of a quality of service liability accrual. The increase was partially offset by a reduction in energy trading overheads reflecting reduced marketing activity.The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in property taxes and a full year of the state excise tax which replaced the state gross receipts tax during 2001.The increase in Income Taxes is predominately due to an increase in state taxes as a result of the State of Ohio s tax legislation resulting from utility deregulation. This increase was offset in part by a decrease in federal taxes due to a decrease in pre-tax operating income.Nonoperating Income and Nonoperating Expense The decrease in Nonoperating Income in 2002 is due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System s traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. CSPCo s share of the AEP Power Pool s gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in Nonoperating Income. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand.The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy trading incentive compensation. Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax nonoperating income.Interest Charges Interest Charges decreased in 2002 primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.F-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income 2002 Year Ended December 31.2001 (in thousands) 2000 OPERATING REVENUES: wholesale Electricity Energy Delivery sales to AEP Affiliates Total operating Revenues OPERATING EXPENSES: Fuel Purchased Power: Wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME S 850,680 492,278 57,202 1.400.160 185,086 15,023 310,605 237,802 60,003 131,624 136,024 104.214 1,180.381 219,779 26,360 S 799,589 483,219 67,511 1,350.319 175,153 10,957 292,199 219,497 62,454 127,364 111,481 99.037 1 098.142 252,177 32,756 21,095 3,923 68,015 191,900 (30.024)161,876 1.095$ 856,998 398,046 49. 365 1,304.409 189,155 9,879 287,750 219,840 69,676 99,640 123,223 109, 369 1.108, 532 195,877 20,580 8,070 7,357 80.828 120,202 (25, 236)94,966 1.783$ ~93,13 NONOPERATING EXPENSES 4,308 NONOPERATING INCOME TAX EXPENSE INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 6,789 53 869 181,173 181,173 1.332$ 179, 841 Consolidated Statements of Comprehensive Income 21 Year Ended December 31.'02 2001 2000 (in thousands) 1,173 $161,876 $94,966 NET INCOME 18: OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability (M COMPREHENSIVE INCOME $12 The common stock of the CSPCo is who7ly owned by AEP.See Notes to Financial Statements beginning on page L-1.(267)9. 090)3261,B 6 594--9-U F-4 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eaminqs Year Ended December 31.2002 2001 2000 (in thousands) Retained Earnings January 1 Net Income Deductions: cash Dividends Declared: Common Stock Cumulative Preferred Stock Total cash Dividends capital stock Expense Total Deductions Retained Earnings December 31$176,103 181,173 357,276 7% series Declared 65,300 350 65,650 1.015 66.665$290,611.$ 99,069 161.876 260.945 82,952 875 83,827 1.015 84.842$i176,13$246,584 94.966 341.550 240,600 1.400 242,000 481 242.481 SL32Pa9 see Notes to Financial Statements beginning on page L-1.F-5 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation $1,582,627 413,286 1,208,255 165,025 98.433 3,467,626 1.465,174 NET ELECTRIC UTILITY PLANT 2,002X452 OTHER PROPERTY AND INVESTMENTS 35.759 LONG-TERM ENERGY TRADING CONTRACTS 77.810$1,574,506 401,405 1,159,105 146,732 72.572 3,354,320 1,377.032 1,977.288 40.369 73. 310 12,358 41,770 63,470 16,968 (745)20,019 38,984 7,087 84,323 28.733 312.967 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Energy Trading Contracts Prepayments and other Current Assets TOTAL CURRENT ASSETS 1,479 31,257 49,566 54,518 22,005 (634)24,844 40,339 12,671 63,348 7.308 306.701 REGULATORY ASSETS 257.682 DEFERRED CHARGES 72,836$2,753,240 262.267 56,187$2,722,388 TOTAL ASSETS see Notes to Financia7 Statements beginning on page L-1.F-6 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock No Par value: Authorized 24,000,000 shares outstanding 16,410,426 shares Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity cumulative Preferred stock subject to Mandatory Redemption Long-term Debt -General Long term Debt Affiliated companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year General Long-term Debt Due within One Year Affiliated Companies short-term Debt Affiliated Companies Advances from Affiliates Accounts Payable General Accounts Payable Affiliated companies Taxes Accrued Interest Accrued Energy Trading Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 41,026 575,384 (59,357)290.611 847,664 418,626 160,000 1,426.290 95,460 43,000 290,000 89,736 81,599 112,172 9,798 46,375 36,790 709.470 437.771 33.907 29.926 20.416$Za53 24Q$ 41,026 574,369 176,103 791,498 10,000 571,348 1.372.846 36,715S 20,500 200,000 181, 384 60,689 83,697 116,364 10,907 72,082 36, 305 781,928 443, 722 37.176 37.101 12.900£tZ722 za83 F-7 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark to Market of Energy Trading Contracts Extraordinary Loss Change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities S 181,173 131,753 23,292 (3,269)(16,667)(3,992)(6,180)(5,584)26,949 (8,027)(22,448)297,000$ 161,876 128,500 24,108 (4,058)(44,680)30,024 19,987 (7,780)2,551 (16,249)(42,066)(18,769)233,444 S 94,966 100,182 (4,063)(3,482)5,352 (3,393)25,236 (29,737)11,957 38,479 81,284 39,483 (121,115)132.44 367,590 INVESTING ACTIVITIES: Construction Expenditures Proceeds From Sales and Leaseback Transactions and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: change in Advances from Affiliates (net)Issuance of Affiliated Long-term Debt Retirement of Preferred Stock Retirement of General Long-term Debt Retirement of Affiliated Long-term Debt Change in short-term Debt (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows used For Financing Activities (136,800) (132,532)730 (136,070)(212,641)160,000 (10,000)(133,343)(200,000)290,000 (65,300)(525)(171 809)10.84 (121.691)92,652 200,000 (5,000)(314,733)(82,952)(962)(110.995)(127,987)1. 560 (126.427)88,732 (10,000)(25,274)(45,500)(240,600)(1.575)(234,217)Net Increase (Decrease) in cash and cash Cash and cash Equivalents January 1 cash and Cash Equivalents December 31 Equivalents (10,879)12.358 3-1"79 758 11,600 S-1 3-5-8 6,946 4.654 S-II&M0 supplemental Disclosure: cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000 and$68,506,000 and for income taxes was $117,591,000, 80,485,000 and $81,109,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were S1,o09,000 and $10,777,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.F-8 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of CaDitalization December 31.2002 2001 (in thousands) COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:. S100 par value authorized shares 2,500,000 525 par value -authorized shares 7,000,000$ 847.664 S 791.493 series Number of shares Redeemed Year Ended December 31, 2002 2001 2000 shares outstanding December 31, 2002 Subject to Mandatory Redemption: 7.00% 100,000 50,000 100,000 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior unsecured Notes Notes Affiliated Junior Debentures Less Portion Due within one Year Total Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 222,797 91,275 147,554 160,000 ( 43.000)578.626 S1L 42,9 243,197 91,220 147,458 200,000 109,973 (220. 500)571. 348 1S1,7-21, A-C see Notes to Financial statements beginning on page L-1.F-9 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) December 31.2002 2001 (in thousands) % Rate Due 7.25 2002 7.15 2002 6.80 2003 6.60 2003 6.10 2003 6.55 2004 6.75 2004 8.70 2022 8.55 2022 8.40 2022 8.40 2022 7.90 2023 7.75 2023 7.60 2024 unamortized Total October 1 S -November 1 May 1 13,000-August 1 25,000 November 1 5,000 March 1 26,500 May 1 26,000 July 1 2,000 August 1 15,000 August 15 14,000 October 15 13,000 May 1 40,000 August 1 33,000 May 1 11,000 Discount (703)$ 14,000 6,500 13,000 25,000 5,000 26, 500 26,000 2,000 15,000 14,000 13,000 40,000 33,000 11,000 (803)% Rate Due 6.85 2005 6.51 2008 6.55 2008 unamortized Total October 3 $ 36,000 February 1 52,000 June 26 60,000 Discount (446)S 36,000 52,000 60,000 (542)Notes payable to parent company were as follows: December 31, 2002 2001 (in thousands) % Rate (a)6.501%Total Due 2002 -Sept 25 S -2006 May 15 160.000 S 160,00$200,000 First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: December 31, 2002 2001 (in thousands)(a) Redemed 9/25/02 Junior debentures outstanding were as follows: December 31, 2002 2001 (in thousands) % Rate Due 8-3/8 2025 7.92 2027 unamortized Total Sept 30 S -March 31 -Discount -5~S 72,843 40,000 (2.870)At December 31, 2002, future annual long-term debt payments are as follows:% Rate Due 6-3/8 2020 -December 1 $48,550 6-1/4 2020 -December 1 43,695 unamortized Discount (970)Total 191,m$48,550 43,695 (1.02 5)2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 43,000 52,500 36,000 160,000 332.245 623,745 (2.119)5621 Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant.F-1 0 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to CSPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CSPCo.The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer Choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Jointly owned Electric Utility Plant -Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 28 Note 29 F-1 I INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 F-1 2 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY Selected Consolidated Financial Data AND SUBSIDIARIES Yea 2002 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income (Loss)Nonoperating Items, Net Interest charges Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$1,526,764 1.375,575 151, 189 16,726 93.923 73,992 4.601 2001$1, 526,997 1.367,292 159,705 9,730 93. 647 75,788 ir Ended December 31.2000 1999 (in thousands) $1,488,209 1.522.911$1,351,666 1.243,014 (34,702) 108,652 1998$1,405,794 1,239,787 166,007 (839)68.540 96,628 4.824 9,933 107. 263 (132,032)4,530 80.406 32,776 4.621 4,885$ 71,167$ 27,891 2002 2001 December 31, 2000 (in thousands) _ _ _ _1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$5,029,958 2,568.604$2,.461,3~54 i48L28719$4,923,721 2.436.972$2,486, 749$4,871,473
- 2. 280.521$2.,590.,952
$4,770,027 2.194.397$2,5575,30 $4,631,848 2.081, 355$2.,550.,493 Total Assets common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption (a)Total Cumulative Preferred stock$ 915,144 (40,487)143.996$ 789,800 (3,835)74,605$ 789,656 3,443$ 789,323 166.389$ 789,189 2 53.154$108,11 $ 8,36 S 793,099 6 $ 9,552, $1 273 S 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 64.945$163,046$1, 617,062 64, 945 11,652-Q&Z 64,945$1,388,939 64.945$£ 74.193$1,324, 3-26 68.445$ 7-7.718 Long-term Debt (a)obligations under capital Leases (a)$ 50,848$ 61L933$-163,173$ 187,965$ 186,427 Total capitalization And Liabilities A 58L7191 4. 394 062$5,774 108$4,575,210 (a) Including portion due within one year.G-1 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 571,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs.maintenance costs incurred as part of planned and unplanned outages at Cook Plant and Rockport Plant.During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection (see Note 5).As a result of costs incurred in 2000 to restart the Cook Plant and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, Net Income increased in 2001 by $208 million. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including l&M, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. The deferrals were expensed and impacted Net Income in 2000.Operatina Revenues Increase Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo s Rockport Plant capacity to KPCo through 2004. The KPCo agreement extends until December 31, 2009 for Rockport Unit I and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. Therefore, l&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.Results of Operations During 2002 Net Income decreased by $2 million due to increased operations and Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase reflects increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in Operating Revenues: Increase (Decrease) From Previous Year (dollars in milions)2002 2001 Amount % Amount %Retail* $ 28.2 Marketing
2.6 other
2.6 Total wholesale Electricity 33.4 Energy Dellvery*
7.3 sales
to AEP Affiliates (40 Total 4 1 6 S (2.3)(12.0)5 .0 N.M (4)13 3 (9.3) (1)2 3.4 1) (16) 44.7) N.M. 3.3 21 3 N.M. = Not Meaningful
- Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.G-2 The increase in Operating Revenues in 2001 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power l&M could sell to its affiliates in the AEP Power Pool.Operating Expenses Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000. The changes in the components of Operating Expenses were: Plant nuclear units for restart with their return to service in 2000. Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002.The increase in Depreciation and Amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of l&M s share of deferred merger costs.Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment of amounts recorded in December 2000 to actual expenses.Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income. The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income.Increase (Decrease)
From Previous Year (dollars in millions)2002 2001 Fuel I wholesale Electricity Purchases AEP Affiliate Purchases Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total I Amount % Amount %'0(10.6) (4) $ 39.2 19 4.7 25 4.9 36 (4.5)13.6 24.3 3.8 (7.8)(15.2)w--(2)3 19 (27.2) (10)(147.7) (25)(92.6) (42)2 9.3 6 (12) 4.9 8 (28) 53.6 N.M.1 ) (10)Nonoperating Income.Expenses and Income Taxes Nonoperating N.M. = Not Meaningful Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs.The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21 %.Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. The decrease in Other Operation and Maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP s traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP s traditional marketing area.Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders incentive compensation. Nonoperating Expenses increased in 2001 due to increased trading overheads and traders incentive compensation. The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income.Interest Charges The decrease in 2001 Interest Charges reflects the recognition in 2000 of deferred G-3 interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998. G-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME (LOSS)NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$ 990,905 321,721 214,138 1. 526. 764 239,455 23,443 233,724 462,707 151,602 168,070 57,721 38. 853 1. 375. 575 151,189 93,739 71,029 5,984 93. 923 73,992 4.601$ 957,548 314,410 255.039 1,526.997 250,098 18,707 238,237 449,115 127,263 164,230 65,518 54.124 1. 367,292 159,705 97,810 83,037 5,043 93 647 75,788 4.621 S 71,167$ 966,882 311,019 210.308 1.488.209 210,870 13,785 265,475 596,861 219,854 154,920 60,622 524 1.522.911 (34,702)76,499 62,377 4,189 107.263 (132,032)4,624$ 315,2656)Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME (LOSS) $ 73,992 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 3,835 Cash Flow Power Hedge (286)Minimum Pension Liability (40,201)COMPREHENSIVE INCOME (LOSS) $ 37, see Notes to Financia7 statements beginning on page L-1.$75,788 $(132,032) (3,835)-Z2 5113Z-02)G-5 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings 2002 Year Ended December 31.2001 (in thousands) 2000 Retained Earnings January 1 Net Income (Loss)Deductions: cash Dividends Declared: Common stock cumulative Preferred stock: 4-1/8% series 4.56% Series 4.12% series 5.90% series 6-1/4% series 6.30% series 6-7/8% series Total Cash Dividends Declared capital stock Expense Total Deductions $ 74,605 73, 992 148, 597 S 3,443 75.788-79.231$ 166,389 (132.032)34. 357 229 66 52 897 1,203 834 1.186 4,467 134 4.601 229 66 72 897 1,203 834 1.186 4,487 139 4.626 26,290 230 66 74 897 1,203 834 1,186 30,780 134 30.914 Retained Earnings December 31 $143 See Notes to Financia7 statements beginning on page L-1.S 74,6L05$3 1 A443 G-6 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 (in thousand 2001 S)ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General (including nuclear fuel)Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$2,768,463 971,599 921,835 220,137 147.924 5,029,958 2.568,604 2.461. 354$2,758,160 957,336 900,921 233,005 74.299 4,923,721 2,436.972 2.486.749 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870.754 834,109 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83, 265 OTHER PROPERTY AND INVESTMENTS 120,941 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading and Derivative Contracts Accrued Utility Revenues Prepayments and other TOTAL CURRENT ASSETS 3,237 191,226 67,333 122,489 30,468 (578)32,731 95,552 68,148 6,511 11,899 629.016 127.977 16,804 46,309 60,864 31,908 25,398 (741)28,989 91,440 108,895 2,072 6.497 418.435 REGULATORY ASSETS 348.212 408,927 DEFERRED CHARGES 73.649 34,967 TOTAL ASSETS$4,58,191 see Notes to Financia7 Statements beginning on page L-1.G-7 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: common Stock -No Par value: Authorized -2,500,000 shares outstanding -1,400,000 Shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION $ 56,584 858,560 (40,487)143 996 1,018,653 8,101 64,945 1.587,062 2,678, 761 620,672 138.965 759.637$ 56,584 733,216 (3,835)74.605 860,570 8,736 64,945 1. 3123082 2.246. 333 600,244 87,025 687,269 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning other TOTAL OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within one Year Accounts Payable General Accounts Payable -Affiliated Companies Taxes Accrued Interest Accrued obligations under capital Leases Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES 30,000 125,048 93,608 71,559 21,481 8,229 48,568 92. 822 491,315 340,000 86,766 43,956 69,761 20,691 10,840 93,413 76 486 741.913 DEFERRED INCOME TAXES 356,197 400,531 DEFERRED INVESTMENT TAX CREDITS 97,709 105,449 DEFERRED GAIN ON SALE AND LEASEBACK -ROCKPORT PLANT UNIT 2 73,885 77, 592 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32, 261 42,936 92,039 REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES $4 58iLL191.$4,3940Q6Z See Notes to Financia7 Statements beginning on page L-1.G-8 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income (Loss)Adjustments for Noncash Items: Depreciation and Amortization Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net)Amortization of Nuclear Outage Costs Deferred Income Taxes Deferred Investment Tax credits Unrecovered Fuel and Purchased Power Costs Changes in Certain Current Assets And Liabilities: Accounts Receivable (net)Fuel, Materials and Supplies Accrued utility Revenues Accounts Payable Taxes Accrued Mark-to-Market of Energy Trading and Derivatives Contracts Disputed Tax and Interest Related to COLI Regulatory Asset Trading Losses Regulatory Liability Trading Gains change in other Assets Change in other Liabilities Net cash Flows From Operating Activities $ 73,992 168,070 (26,577)40,000 (16,921)(7,740)37,501 (102,283)(7,854)(4,439)87,934 1,798 (9,517)(992)2,494 (28,233)21.001 228.234$ 75,788 166,360 418 40,000 (29,205)(8,324)37,501 64,841 (19,426)(2,072)(60,185)1,345 (62,647)8,493 34,293 (5,871)(5,102)236,207$ (132,032)163,391 5,737 40,000 (125,179)(7,854)37,501 (25,305)10,743 44,428 85,056 19,446 14,830 56,856 (17,914)(7,416)(68,160)37.309 131.437 INVESTING ACTIVITIES: Construction Expenditures Bu yout of Nuclear Fuel Leases Other Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES: capital Contributions from Parent Company Issuance of Long-term Debt Retirement of cumulative Preferred Stock Retirement of Long-term Debt change in Advances from Affiliates (net)change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and Cash Equivalents January 1 cash and cash Equivalents December 31 (167,484)1. 759 (165 .72 5)125,000 288,732 (424)(340,000)(144,917)(4.467)(76.076)(91,052)(92,616)1,074 (182.594)297,656 (44,922)(299,891)(4.487)(51.644)(171,071)587 (170.484)199,220 (314)(148,000)253, 582 (224,262)(26,290)(3. 368).50. 568 (13,567)16.804 1,969 11,521 14.835 3,314 l_6104 S 14, 835 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000 and$82,511,000 and for income taxes was $60,523,000, $100,470,000 and $73,254,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,023,000 and$22,218,000 in 2001 and 2000, respectively. see Notes to Financial Statements beginning on page L-1.G-9 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) $1.018.653 S 860.570 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:$100 Par value -Authorized 2,250,000 shares$25 Par value -Authorized 11,200,000 shares call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not Subject to Mandatory Redemption-$100 Par: 4-1/8% 106.125 20 -3,750 4.56% 102 ---4.12% 102.728 6,326 -1,375 Subject to Mandatory Redemption-S100 Par(b): 5.90% (c) ---6-1/4% (c) ---6.30% (c) ---6-7/8% (d) ---shares outstanding December 31. 2002 55,369 14,412 11,230 152,000 192,500 132,450 172,500 5,537 1,441 1. 123 8.101 15,200 19,250 13,245 17.250 64.945 5,539 1,441 i1. 756 8.736 15,200 19, 250 13,245 174 950 64.945 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 174,245 264,141 Installment Purchase Contracts 310,336 310,239 senior unsecured Notes 747,027 696,144 other Lon -term Debt (e) 223,736 219,947 Junior Debentures 161,718 161,611 Less Portion Due within one Year (30.000) (340.000)Long-term Debt Excluding Portion Due within one Year 1.587,062 1.312,082 TOTAL CAPITALIZATION 4S2j1 SZ,2A33 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends (b) sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of these due dates. Shares previously purchased may be applied to meet the sinking fund requirement. cc) commencing in 2004 and continuing through 2008 I&M may redeem at $100 per share, 20,000 shares of the 5.90%series, 15,000 shares of the 6-1/4% series and 17,500 shares of? the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. The series are callable beginning November 1, 2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March 1, 2004 for the 6.30% series at $100 plus accrued dividends.(d) commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. callable at $100 per share plus accrued dividends beginning February 1, 2003.(e) Represents a liability for SNF disposal including interest payable to the DOE. See Note 9.See Notes to Financial Statements beginning on page L-1.G-10 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 7.60 2002 7.70 2002 6.10 2003 8.50 2022 7.35 2023 7.20 2024 7.50 2024 unamortized November 1 December 1-November 1-December 1 October 1 February 1 March 1 Discount.S 30,000 5 75,000 15,000 30,000 25.000 (75 5)$ 50,000 40,000 30,000 75,000 15,000 30,000 25,000 (859)The terms of* the installment purchase contracts require l&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date).Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) December 31.2002 2001 (in thousands) % Rate Due (a) 2002 6-7/8 2004 6.125 2006 6.45 2008 6.375 2012 6 2032 unamortized September 3 S -3uqy 1 150,000 December 15 300,000 November 10 50,000 November 1 100,000 December 31 150,000 Discount (2.973)S7AL 02$200,000 150,000 300,000 50,000 (3.856)% Rate Due City of Lawrenceburg, Indiana: 7.00 2015 April 1 S 25,000 5.90 2019 -November 1 52,000 city of Rockport, Indiana: (a) 2014 August 1 7.60 2016 March 1 6.55 2025 June 1 (b) 2025 June 1 4.90(c) 2025 June 1 city of Sullivan, Indiana: 5.95 2009 May 1 unamortized Discount I1 S 25,000 52,000 50,000 40,000 50,000 50,000 (a) A floating interest rate was determined quarterly. The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.Junior debentures outstanding were as follows: December 31.2002 2001-in thousands) 40,000 50,000 50,000 50,000% Rate Due 8.00 2026 7.60 2038 unamortized Total March 31 S 40,000 June 30 125,000 Discount (3 282)S161 71 S 40,000 125,000 (3.389)45,000 45,000 (1.664) (1 761)t3036 S1 3 (a) A variable interest rate was determined weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001.(b) In June 2001 an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for 2002 ranged from 1.3% to 1.7% and averaged 1.5%. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9%to 4.9% in 2001 and averaged 3.3% during 2001.(c) Rate is fixed until June 1, 2007 (term rate bonds).Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 30,000 150,000 300,000 50,000 1.095.736 1,625,736 (8.674)51 617 06 G-1 I INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to combined Notes to Consolidated Financial statements The notes to I&M s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1.significant Accounting Policies Merger Nuclear Plant Restart Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and Sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 5 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 G-12 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America./sI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 G-13 KENTUCKY POWER COMPANY KENTUCKY POWER COMPANY Selected Financial Data Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Net Income$ 378,683 336.486 42,197 5,206 26.836$ 20,567$ 379,025 331. 347 47,678 1,248 27. 361$ 21,565$ 389,875 340.137 49,738 2,070 31.045 20,76i3$ 358,757 304.082 54,675 (327)28.918$ 2iA3A0$ 362,999 311.106 51,893 (1,726)28.491 kS _21,676 Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common Stock and Paid-in Capital Accumulated Other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$1,295,619 397, 304$1,164,676 $ 259,200 (9,451)48.269$1,128,415 384.104$ 744,311 S 999,048$ 209,200 (1,903)$1,103,064 360.648 S 742,416$1,494,543 $ 209,200 57.513 S_266,713$1,079,048 340.008$ 739.040$ 986.123$ 209,200 67.110$ 2 6,310$1,043,711 315. 546$ 728 165$ 921,3A7$ 199,200 71.,452 Si248 0-18 Lon -term Debt (a)Debt ( )3 963632$ 346-093 5-365.,782 L_3 68-838 obligations Under Capital Leases(a)Total Capitalization and Liabilities I1164. 676$1,494,543 $921,84 (a) Inc7uding portion due within one year.H-1 KENTUCKY POWER COMPANY Management s Narrative Analysis of Results of Operations KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. KPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs.KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP s settlement restructuring agreement filed with the FERC becomes operative. The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Underthe unit power agreement, there is a demand charge for the right to receive the power, which is payable even it the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity.Results of Operations Net Income for 2002 decreased $1 million or 5%.Total Revenues were flat while increases in Operating Expenses, driven by expenses related to planned outages at the Big Sandy plant, were offset by comparable gains in net nonoperating income which benefited from decreases in trading incentive compensation. Changes in Revenues wholesale Electricity* Energy Delivery*Sales to AEP Affiliates Total Increase (Decrease) Year-to-Date (dollars in milions Amount %$13 6 j!) C(34)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Revenues in 2002 were comparable to those of last year. Increased sales to retail electricity customers reflecting warmer summer weather, colder days in late 2002, and increased fuel recovery revenues were offset by lower Sales to AEP Affiliates resulting from planned outages in 2002. KPCo s decreased generation was due to scheduled maintenance resulting in lower availability in the fourth quarter.Changes in Operating Expenses Increase (Decrease) Year-to-Date (dollars in millions)Amount %S(5.6) (8)-N.M.Fuel wholesale Electricity Purchases from AEP Affiliates other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Total Operating Expenses N.M. = Not Meaningful 2.8 (5.4)12.6.7.4-E4)2 (9)56 2 5 (4)2 Fuel expense decreased in 2002 as a result of planned fourth quarter outages at the Big Sandy H-2 plant for scheduled boiler maintenance. The 800 megawatt Unit 2, representing approximately 75%of the plants generation capacity, was off-line from mid-September through the end of the year, thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to meet demand during the planned outages at the Big Sandy plant.Other Operation expense decreased in 2002 due to reduced consumption of emission allowances due to the planned outage; reduced accruals for trading incentive compensation due to reduced trading activity; and improvements in transmission expense resulting from less wholesale activity and related transmission, and an increase in AEP transmission equalization credits. Underthe AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company s peak demand and investment. A decrease in KPCo s peak demand relative to its affiliates peak demand was the main reason for the increase in transmission equalization credits. These developments were offset in part by severance expenses related to a sustained earnings initiative (see Note 11).Nonoperating Income Taxes for 2002 have increased as a result of increases in pre-tax income for the year offset in part by prior-year tax return adjustments. Other Changes Nonoperating Income for 2002 decreased as a result of AEP s previously announced plan to reduce trading activity, and decreased margins on power trading activity outside of the AEP System s traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased in 2002 as a result of decreases in trading incentive compensation. Maintenance expense increased in 2002 primarily as a result of planned power plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for planned boiler overhaul and electric plant maintenance. The Company experienced marginal increases in overhead line maintenance expense.H-3 --KENTUCKY POWER COMPANY Statements of Income Year 2002 (in Ended December 31.2001 2000 thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES$218,665 132,054 27,964 378.683 65,043 29 133,002 52,892 35,089 33,233 8,240 8.958 336,486 42,197 7,863 753 1,904 26,836 20.567$205,476 131,183 42. 366 379.02 5 70,635 86 130,204 58,275 22,444 32,491 7,854 9. 358 331, 347 47,678 10,881 8,949 684 27. 361 La25=U6$226,708 121,346 41.821 389,875 74,638 1,940 127,707 52,495 25,866 31,028 7,251 19,212 340.137 49,738 6,139 2,940 1,129 31.045 L 20,76 NET INCOME Statements of Comprehensive Income 2002 NET INCOME $ 20,5b7 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 2,225 Minimum Pension Liability (9.773)COMPREHENSIVE INCOME $1 3, ol Statements of Retained Earnings 2002 RETAINED EARNINGS JANUARY 1 $48,833 NET INCOME 20,567 CASH DIVIDENDS DECLARED 21,131 RETAINED EARNINGS DECEMBER 31 See Notes to Financial statements beginning on page L-1.Year Ended December 31, 2001 2000 (in thousands) $21,565 $20,763 (1,903)Year Ended December 31.2001 (in thousands) $57,513 21,565 30.245$A&2000$67,110 20,763 30.360 H4 KENTUCKY POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Accrued Tax Benefit Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial statements beginning on page L-1.$ 275,121 373,639 425,817 55,913 165.129 1,295,619 397.304 898.315 6.904 29.871 2,304 22,044 23,802 2,889 (192)10,817 16,127 5,301 1,253 24,320 2,127 110,792 101,976 16.818$1,164,676 S 271,070 374,116 402,537 65,059 15.633 1,128,415 384.104 744.311 6,492 29.477 1,947 20,036 16,012 3,333 (264)12,060 15,766 5,395 33,905 1,314 109,504 97.692 11,572 SL999,048 H-5 KENTUCKY POWER COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock $50 Par value: Authorized 2,000,000 shares outstanding 1,009,000 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareowner S Equity Long-term Debt Long-term Debt Affiliated Companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year -General Long- term Debt Due within one Year -Affiliated Companies Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.S 50,450 208,750 (9,451)48.269 298,018 391,632 60.000 749,650 27. 319 15,000 23,386 46,515 44,035 8,048 6,471 17,803 14. 322 175. 580 178,313 9,165 11.488 13.161$ 50,450 158,750 (1,903)48.833 256,130 176,093 75,000 507. 223 11.929 95,000 66,200 23,464 22,557 4,461 10,305 5,269 38,664 12,882 278,802 168,304 10,405 14,917 7,468 S1,164,676 H-6 KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark-to-Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities $ 20,567 33,233 9,839 (1,240)2,998 (12,267)(9,426)882 94 44,529 (11,558)(21,491)16.161 72, 321$ 21,565 $ 20,763 32,491 6,293 (1,251)(4,707)(1,454)23,694 (7,658)1,105 (22,942)(1,580)(2,762)(9,446)33, 348 31,034 3,765 (1,252)2,948 (4,376)(20,930)8,386 7,237 39,883 2,025.5,943 62,653 (62. 702)95, 377 INVESTING ACTIVITIES: construction Expenditures Proceeds From Sales of Property Net Cash Flows Used For Activities Investing (178,700)217 (178,483)(37,206)216 (36 990)(36,209)266 (35.943)FINANCING ACTIVITIES: capital contributions from Parent Company Issuance of Long-term Debt Retirement of Long-term Debt change in short-term Debt (net)change in Advances From Affiliates (net)Dividends Paid Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 50,000 274,964 (154, 500)(42,814)(21.131)106,519 357 1$947 3-2.3-04 75,000 (60,000)18,564 (30,245)3, 319 (323)2,270$ 1,947 69,685 (105,000)(39,665)47,636 (30 ,360)(57.704)1,730 540-2,270 supplemental Disclosure: Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000 and$28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $22,021, $817,000 and$2,817,000 and in 2002, 2001 and 2000, respectively. see Notes to Financial Statements beginning on page L-1.H-7 KENTUCKY POWER COMPANY Statements of Capitalization December 31, 2002 2001 (in thousands) $298.018 $256.130 COMMON SHAREHOLDER S EQUITY LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Senior unsecured Notes Notes Payable Junior Debentures Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 statements beginning on page L-1.352,508 75,000 39,124 (15.000)451.632$7A9,6iQ 59,383 147,625 100,000 39,085 (95.000)251.093 5507.2_2 H-8 KENTUCKY POWER COMPANY Schedule of Lonq-term Debt First mortgage bonds follows: outstanding were as December 31.2002 2001 (in thousands) % Rate Due 6.65 2003 6.70 2003 6.70 2003 7.90 2023 Unamortized Notes payable to banks outstanding were as follows: December 31.2002 2001 (in thousands) X Rate Due 7.45 2002 September 20 S -=Junior debentures outstanding were as follows: May 1 June 1 July 1 June 1 Discount S S 15,000 15,000 15,000 14,500 il 17)First mortgage bonds were secured by a first mortgage lien on electric utility plant.Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) % Rate Due 8.72 2025 June 30 unamortized Discount Total 540,000 (876)539,12$40,000 (915)539 08% Rate Due (a) 2002 6.91 2007 6.45 2008 5.50 2007 4.31 2007 4.37 2007 unamortized December 31.2002 2001 (in thousands) -November 19 S -S 70,000 October 1 48,000 48,000 November 10 30,000 30,000 July 125,000 -November 12 80,400 -December 12 69,564 -Discount (456) (375)S3258S4,Z Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.At December 31, 2002, future annual long-term debt payments are as follows: (a) A floating interest rate is determined monthly. The rate December 31, 2001 was 4.3%.Notes payable to parent company were as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 15,000 60,000 322,964 70.000 467,964 (1.332)S466,-632% Rate Due 4.336 2003 6.501 2006 December 31.2002 2001 (in thousands) $15,000 S15,000 60.000 60.000 S75,00 57,0 May 15 May 15 H-9 KENTUCKY POWER COMPANY Index to combined Notes to Financial statements The notes to KPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1.Significant Accounting Policies Merger Rate Matters Effects of Regulation Commitments and Contingencies Guarantees Sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 6 Note 7 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 H-10 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 H-I 1 OHIO POWER COMPANY OHIO POWER COMPANY Selected Financial Data 2002 Year Ended December 3 2001 2000 (in thousands) .INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable To Common stock$2,113,125 1.814,796 298,329 5,376 83. 682 220,023 220,023 1.258$2,098,105 1.857, 395 240,710 18,686 93.603 165,793 (18. 348)147,445 1.258$ 146,187$2,140,331 1.913. 504 226,827 (5,004)119,210 102,613 (18.876)83,737 1.266$ 82,471 1999$1,978,826 1.689.997 288,829 7,000 83.672 212,157 212,157 1,417 LI210,740 1998$2,105,547 1,816.175 289,372 588 80,035 209,925 209,925 1.474 L 20845 2002 December 31, 2001 2000 (in thousands) -A -A ----BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$5,685,826 2.566.828$5,390,576 2.452 571$5,577,631 2.764.130$2.813 .50 361397.5$5,400,917 2.621.711$2 779,206$4. 675,5 1998$5,257,841 2,461.376$2,796,465 $4,344,68$4.457.032,93SiIM Common stock and Paid-in Capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common Shareholder's Equity$ 783,684 (72,886)522.316$ 783,684 (196)401.297$ 783,684 398.086 S1A8181Z0$ 783,577 587.424$ 783,536 587. 500 Cumulative Preferred stock: Not subject to Mandatory Redemption $ 16,648 subject to Mandatory Redemption (a) 8.850 Total Cumulative Preferred stock $ 2549 Long-term Debt (a) $1,067,314 obligations under capital Leases (a) $&65,_626 Total capitalization and Liabilities $4,457,03$ 16,648 8.850$ 16,648 8.850$ 16,937 8.850$ 17,370 11,850 SZ5__M 25.4982~2~ S fL8--6&66$6.193,975 t$A__42, 635$4,675,159 (a) Including portion due within one year.1-1 -OHIO POWER COMPANY Management s Discussion and Analysis of Results of Operations Ohio Power Company (OPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 702,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each company's percentage share of AEP Power Pool revenues and costs.Results of Operations Income Before Extraordinary Item increased$54 million or 33% in 2002 mainly due to reductions in operating expenses, predominantly fuel, and interest charges.Income Before Extraordinary Item increased$63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI)program recorded in 2000. In February 2001 the U.S. District Court forthe Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP s consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net Income was also favorably impacted by the growth in and strong performance by the wholesale business. The effects of the COLI decision in 2000 and favorable wholesale business in 2001 were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the economic downturn.Operating Revenues Operating Revenues increased 1% in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were: Increase (Decrease) From Previous Year (Dollars in Millions)2002 2001 Amount % Amount %Retail* $ 11 2 S(66) (8)wholesale Marketing 10 5 (19) (8)unrealized MTM 2 8 33 N.M.Other 1 1 (4) (5)Total wholesale Electricity* 24 2 (56) (5)Energy Delivery* 37 7 85 18 Sales to AEP Affiliates (46) (9) (71) (12)Total SL15 1 VA42) (2)* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 39%. For the fall season, heating degree days increased 32%. This 1-2 reflects a return to more normal weather conditions since 2001 weather was abnormally mild. Sales to AEP Affiliates decreased due to a 15% decrease in price, reflective of lower average fuel cost, while MWH sales rose slightly.Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool. This was the result of an affiliate being able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000.Operating Expenses Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel. Operating Expenses in 2001 also decreased 3%. This reduction was the result of lower Fuel and Income Taxes partially offset by amortization of transition regulatory assets.due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate s two nuclear units returning to service.Wholesale Electricity Purchased Power expense increased in 2002. This was the result of a 11% increase of MWH sales, partially offset by a decrease in price. In 2001 the increase was due to increases in MWH purchases from third parties because of the non-availability of associated nuclear power for resale to wholesale customers and to meet internal demand.AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18%increase of MWH purchased from affiliates with a slight decrease in the average price.The increase for 2001 was also a result of increased purchases through the AEP Power Pool.Changes in the Expenses were: Fuel wholesale Electricity Purchased Power AEP Affiliates Purchased Power Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes Total operating Expenses components of Operating Increase (Decrease) From Previous Year (dollars in millions)2002 2001 Amount % Amount %Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Spom plants, and boiler inspections at the Amos and Cardinal Plants.S C In 2001, the commencement of amortization 102) (15) 5(85) (11) of transition regulatory assets in connection 4 6 is 30 with the transition to customer choice and market-based pricing of retail electricity supply 8 14 12 23 under Ohio deregulation accounted for the 16 4 (4) (1)(6) (4) 18 15 significant increase in Depreciation and 9 4 84 54 Amortization expense.12 SLU4)10 12 (2)(10)(86)(6)(46)(3)The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWH generated. The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal.Fuel expense decreased 11 % in 2001 mainly The 2002 increase in Taxes Other Than Income Taxes is the result of increases in state excise tax created from a change in the base tax calculation. The decrease in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax.Income Taxes increased in 2002 due to an increase in both federal and state tax 1-3 -expenses. Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis.State taxes increased predominately as a result of the State of Ohio s tax legislation revision involving utility deregulation. Income Taxes decreased in 2001 due to an unfavorable ruling in AEP s suit against the government over interest deductions claimed relating to AEP s COLI program which was recorded in 2000 and a decrease in pre-tax book income.Nonoperating Income and Nonoperating Expense The major reason for the decrease in Interest Charges in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. Extraordinary Loss In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.Nonoperating Expenses decreased during 2002 due to reductions in variable incentive compensation expenses associated with wholesale trading.Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of an increase in the level of trading activity outside of the AEP System s traditional marketing area.The 2002 increase in Nonoperating Income Tax Expense is a result of the favorable tax benefit from the sale of the Ohio Coal companies in 2001. This event also caused the decrease for 2001.Interest Charges The 2002 decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.1-4 OHIO POWER COMPANY Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING REVENUES: Wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (See Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK$1,058,250 589,673 465.202 2,113.125 584,730 67,385 71,154 416,533 136,609 248,557 176,247 113.581 1.814.796 298,329 51,953 28,567 18,010 83.682 220,023 220,023 1.258$ 218,765$1,034,026 552,713 511,366 2.098.105 686, 568 63,441 62,585 400,790 142,878 239,982 159,778 101,373 1.857. 395 240,710 70,108 53,802 (2,380)93.603 165,793 (18.348)147,445 1.258$ 146.187$1,090,297 467,587 582.447 2.140.331 771,969 48,657 50,741 404,410 124,735 155,944 169,527 187.521 1.913.504 226,827 57,163 44,009 18,158 119.210 102,613 (18.876)83,737 1,266 Statements of Comorehensive Income 2002 Year Ended December 31.(in thousands) 2001 023 $147,445 $NET INCOME $2 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability COMPREHENSIVE INCOME 3 The common stock of oPco is wholly owned by AEP.See Notes to Financial statements beginning on page L-1.1-5 220, (542)(72.148)147,333 (196)$147,249 I 2000;83,737 OHIO POWER COMPANY Statement of Retained Earninqs Year Ended December 31.2002 2001 (in thousands) $398,086 147.445 545.531 2000 Retained Earnings January 1 Net Income$401,297 220,023 621,320$587,424 83,737 671. 161 Deductions: cash Dividends Declared: Common stock Cumulative Preferred Stock: 4.08% series 4.20% series 4.40% Series 4-1/2% Series 5.90% series 6.02% Series 6.35% series Total Dividends 97,746 58 96 139 439 428 66 32 99,004 142,976 271,813 58 96 139 439 428 66 32 144,234 59 96 139 442 428 66 32 273,075 Retained Earnings December 31 see Notes to Financia7 statements beginning on page L-1.MZJI-6 $AO1,291 $3-9&JO 1-6 OHIO POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES$3,116,825 905,829 1,114,600 260,153 288.419 5,685,826 2. 566.828 3.118.998 61,686 103.230 5,285 95,100 124,244 19,281 (909)87,409 85,379 92,108 12.083 519.980 568.641 84.497 SAA45 t932$3,007,866 891,283 1,081,122 245,232 165,073 5,390,576 2.452.571 2.938.005 62.303 99.706 8,848 84,694 148,563 20,409 (1,379)84,724 88,768 114,280 20,865 569.772 644.625 79.662 4A07 TOTAL ASSETS see Notes to Financial statements beginning on page L-1.1-7 OHIO POWER COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock No Par value: Authorized 40,000,000 shares outstanding 27,952,473 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity Cumulative Preferred Stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year -General Long-term Debt Due within one Year Affiliated Companies short-term Debt Affiliated Companies Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued obligations under Capital Leases Energy Trading Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 321,201 462,483 (72,886)522. 316 1,233,114 16,648 8,850 917.649 2. 176.261 227,689 89,665 60,000 275,000 129,979 170,563 145,718 12,969 111,778 18,809 14,360 61,839 80.608 1,171,288 794.387 18.748 39,702 28.957 54,45,032$ 321,201 462,483 (196)401,297 1,184,785 16,648 8,850 1.203,841 2.414.124 130, 386 300,213 131,057 176, 520 5,452 126,770 17,679 16,405 98,081 90.431 962.608 797.889 21.925 50,459 16.682$4,3-9A4-0173 1-8 OHIO POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation, Depletion and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Extraordinary Loss Mark to Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Customer Deposits Taxes Accrued Disputed Tax and Interest Related to COLI Employee Benefit and other Noncurrent Liabilities Impairment Loss change in other Assets change in other Liabilities Net Cash Flows From Operating Activities $ 220,023 248,557 46,010 (3,177)(28,693)14,571 704 3,081 8,704 7,517 (14,992)110,298 1,757 (2,233)(133.154)478.973$ 147,445 252,123 215,833 (3,289)18,348 (59,833)51,640 4,852 264 9,887 (34,284)(96,331)(392,026)79,831 (107.704)86.756 S 83,737 200,350 (65,956)(3,399)(56,869)18,876 (5,614)51,430 46,645 45,311 56,069 31,540 60,919 110,494 145,573 (439,448)359.640 639,298 INVESTING ACTIVITIES: Construction Expenditures Proceeds From Sales of Property and other Investment in coal Companies Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: Issuance of Long-term Debt change in Advances From Affiliates (net)Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Decrease in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 (354,797)6,499 (348,298)(170,234)(140,000)275,000 (97,746)(1.258)(134.238)(3,563)8.848$ S5, (344,571)16,778 (32,115)(359.908)300,000 392,699 (297,858)(142,976)(1,258)250,607 (22,545)31. 393 (254,016)6,354 (247,662)74,748 (92,486)(182)(30,663)(194,918)(271,813)(1,262)(516, 576)(124,940)156.333 supplemental Disclosure: cash paid (received) for interest net of capitalized amounts was $81,041,000, $94,747,000 and$87,120,000 and for income taxes was $105,058,000, $(22,417,000) and $142,710,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $106,000,$2,380,000 and $17,005,000 in 2002, 2001 and 2000, respectively. See Notes to Financia7 Statements beginning on page L-1.1-9 11 OHIO POWER COMPANY Statements of CaDitalization December 31.2002 2001 (in thousands) $1.233.114 S1.184.785 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 3.762,403$25 par value -authorized shares 4,000,000 call Price shares December 31, Number of shares Redeemed outstanding series 2002 (a) Year Ended December 31. December 31. 2002 2002 2001 2000 Not Subject to Mandatory Redemption-S100 Par: 4.08% $103 ---14,595 4.20% 103.20 --276 22,824 4.40% 104 --432 31,512 4-1/2% 110 --2.181 97.546 subject to Mandatory Redemption-S100 Par (b): 5.90% (c) $ ---6.02% (d) ---6.35% (d) ---1,460 2,282 3,151 9. 755 16. 648 7,250 1, 100 500 8.850 1,460 2,282 3,151 9. 755 16. 648 7,250 1,100 500 8.850 72,500 11,000 5,000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 136,633 141,544 Installment Purchase Contracts 233,340 233,235 senior unsecured Notes 397,341 396,962 Notes Payable to Affiliated company 300,000 300,000 Junior Debentures -132,100 Less Portion Due within one Year (149.665) -Long-term Debt Excluding Portion Due within one Year 917,649 1.203.841 TOTAL CAPITALIZATION 52 626 S2,414,14Z (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends.(b) sinking fund provisions require the redemption of 35,000 shares in 2003 and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due dates. shares previously purchased may be applied to the sinking fund requirement. At the company s optioni all shares are redeemable at S100 per share plus accrued and unpaid dividends with at least 30 days notice beginning on or after November 1, 2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April 1, 2003 for the 6.35% series.(c) commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. shares previously redeemed may be applied to meet sinking fund requirements.(d) Commencing in 2003 and continuing through 2007 sinking fund provisions will require the redemption of 20,000 shares each year of the 6.02% series and 15,000 shares each year of the 6.35% series, in each case at $100 per share. All remaining outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirements. See Notes to Financial Statements beginning on page L-1.1-10 OHIO POWER COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 6.75 2003 6.55 2003 6.00 2003 6.15 2003 (a) 2022 7.75 2023 7.375 2023 7.10 2023 7.30 2024 Unamortized Total April 1 S 29,850 October 1 27.315 November 1 12,500 December 1 20,000-February 10 -April 1 5,000 October 1 20,250-November 1 12,000 April 1 10,000 Discount (282)1135 633 S 29,850 27,315 12,500 20,000 5,000 5,000 20,250 12,000 10,000 (371)5141, 4A sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands)(a) Redeemed on May 10, 2002.First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 6.75 2004 7.00 2004 6.73 2004 6.24 2008 7-3/8 2038 unamortized Total July 1 $100,000 July 1 75,000 November 1 48,000 December 4 37,225 June 30 140,000 Discount (2.884)S37,4$100,000 75,000 48,000 37,225 140,000 (39263)Notes payable to parent company were as follows:% Rate Due 4.336% 2003 6.501% 2006 Total May 15 May 15 December 31.2002 2001 (in thousainds) S 60,000 S 60,000 240.000 240.000 Sa_,0 outstanding were as December 31.2002 2001 (in thousands) Junior debentures follows:% Rate Due Mason County, West Virginia: 5.45% 2016 December Marshall county, West Virginia: 5.45% 2014 July 1 5.90% 2022 April 1 6.85% 2022 June 1 Ohio Air Quality Development 5.15% 2026 May 1 unamortized Discount Total December 31.2002 2001 (in thousands) I S 50,000 S 50,000 50,000 50,000 35,000 35,000 50,000 50,000% Rate Due (a) 2025 (a) 2027 unamortized Total September 30 S -S 85,000 March 31 -50,000 Discount -(2.900)1 -si (a) Redeemed on July 24, 2002 At December 31, 2002 future annual long-term debt payments are as follows: 50,000 (1.660)12I33,34 50,000 (1.765)Under the terms of the installment purchase contracts, OPCo is required to pay amounts 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 149,665 223,000 240,000 459.475 1,072,140 4 826 1-11 OHIO POWER COMPANY Index to combined Notes to Financial statements The notes to OPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans Business segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 1-12 INDEPENDENT AUDITORS'REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying balance sheets and statements of capitalization of Ohio Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Ohio Power Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.1s1 Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 1-13 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income Preferred stock Dividend Requirements Gain on Reacquired Preferred stock Earnings Applicable to Common stock$ 793,647 708.926 84,721 (3,239)40.422 41,060 213$957,000 860.012 96,988 20 39.249 57,759 213$956,398 859.729 96,669 8,974 38,980 66,663$749,390 650.677 98,713 946 38.151 61,508 212$780,159 665.085 115,074 (91)38.074 76,909 212 213 1$ 40.848 LiZJ_.~ 1_0,A5I1 S-512% 9 6 $76-, 2002 December 31.2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$2,759,504 1.239,855$i,519,649 $1,76,69$2,695,099 1.184.443$1,510,656 $2,604,670 1.150.253$1.,454,417 $2,459,705 1,114.255$1 , 3A5,45Q 24$2,391,722 1.082.081 Total Assets$IAZ10 Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity$ 337,246 (54,473)116.474 S 399,247$ 337,246 142.994$ 480s2A0$ 337,246 137,688$ 474,934$ 337,246 139.237 S 476,483 S 337,246 142. 941 cumulative Preferred Stock: Not subject to Mandatory Redemption Preferred securities of subsidiary Trust Long-term Debt (a)$ 5. 27$LJ575000 S 75QQ0$ 545,437$ 451,129$_384,064 Total capitalization and Liabilities$1,748,911 $1.I 524, 846 S1,471,09 (a) Including portion due within one year.J-1 L. i PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Management s Narrative Analysis of Results of Operations Public Service Company of Oklahoma (PSO)is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing activities are conducted on PSO s behalf byAEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. Results of Operations In 2002, Net Income decreased by $17 million or 29% primarily resulting from reduced wholesale margins and increased depreciation expense.Changes in Operating Expenses Increase (Decrease) From Previous Year (dollars in millions)Amount %S(215.3) (47)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 23.3 45.7 (4.1)1.9 96 104 (3)4 5.6 7 2.1 (10.3)S(514)7 (30)(18)N.M. = Not Meaningful The decrease in Fuel expense in 2002 was primarily due to lower market prices for natural gas and fuel oil, and deferral of underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and to the amortization of previously overrecovered fuel costs.Changes in Operating Revenues Operating revenues decreased in 2002 as a result of reduced wholesale margins, a decline in fuel recovery revenue and decreases due to the interchange cost reconstruction (ICR) adjustments (see Note 6).Increase (Decrease) From Previous Year (dollars in millions)Amount %wholesale Electricity* S(149.7) (23)Energy Delivery* 13.6 5 sales to AEP Affiliates t27.3) (74)Total operating Revenues S(163) (17)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.The increase in Electricity Marketing Purchased Power expense in 2002 resulted mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices.The increase in the AEP Affiliates Purchased Power expense in 2002 resulted mainly from the ICR adjustments (see Note 6).Other Operation expense decreased in 2002 primarily due to lower transmission expenses and decreased factoring expenses due to reduced revenues.Maintenance expense increased, in 2002 largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002.Depreciation and Amortization expense increased in 2002 primarily due to the additional depreciable capitalized costs involved in repowering NortheastStation Units 1 & 2 completed in 2001.Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in ad valorem taxes.J-2 Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.Other Changes Nonoperating Expenses increased primarily due to the write-down of certain non-utility investments in 2002.J-3 --t PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Income Year Ended December 31.2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES$508,661 275,547 9,439 793,647 246,199 47,507 89,454 133,538 48,060 85,896 34,077 24.195 708.926 84,721 1,920 6,971 (1,812)40.422 ZO21 (in thousands) $658,352 261,877 36.771 957.000 461,470 24,187 43,758 137,678 46,188 80,245 31,973 34,513 860.012 96,988 2,112 1,740 352 39.249 2000$696,626 245,124 14, 64 8 956. 398 402,933 88,088 60,788 121,697 45,858 76,418 28,688 35,259 859.729 96,669 8,807 1,139 (1,306)38.980 NET INCOME GAIN ON REACQUIRED PREFERRED STOCK LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 41,060 1 213 57,759 213 ,$L5 66,663 212$ 66A S5$ 40,848 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 2000 (in thousands) $ 41,060 $57,759 $66,663 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(42)(54.431)$ (13.413)$5ZL75-9 I The common stock of P50 is owned by a wholly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-4 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Retained Eaminqs Year Ended December 31, 2002 2001 (in thousands) $137,688 57,759 2000$139,237 66,663 BEGINNING OF PERIOD NET INCOME DEDUCTIONS: capital Stock Gains Cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$142,994 41,060 (1)67,368 213$116,474 52,240 213 68,000 212$142,994 1IaL&6 The common stock of P50 is owned by a who ly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-5 It i -PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$1,040,520 432,846 990,947 206,747 88.444 2,759,504 1.239.855 1.519.649 OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: Customers Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS 4.481 16,774 31,687 14,139 (84)19,973 37,375 76,470 3,841 2.735 202.910$1,034,711 427,110 972,806 203,572 56.900 2,695,099 1,184.443 1,510,656 41.020 21. 354 5,795 31,144 10,905 (44)21,559 36,785 756 26,259 2.368 135. 527 REGULATORY ASSETS 26. 150 DEFERRED CHARGES 18.117 TOTAL ASSETS$1. 748. 911 See Notes to Financial statements beginning on page L-1.J-6 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CAPTTALIZATION AND LIARILTTIFS December 31, 2002 2001 (in thousands) CAPITALIZATION: Common Stock $15 Par value: Authorized shares: 11,000,000 Issued Shares: 10,482,000 outstanding Shares: 9,013,000 Paid-in capital Accumulated Other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred stock Not subject to Mandatory Redemption Pso-obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Over-Recovered Fuel Costs Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS REGULATORY LIABILITIES AND DEFERRED CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.S 157,230 180,016 (54,473)116,474 399. 247$ 157,230 180,016 142.994 480.240 5,267 5,267 75,000 445.437 924.951 54.761 100,000 86,105 61,169 78,076 21,789 6,854 6,979 3,260 24. 957 389.189 341.396 32.201 32.611 1,581$1,776,690 75,000 345.129 905.636 7,263 106,000 123,087 72,759 40,857 21,041 9,476 18,150 7,298 31,718 12,216 442.602 296.877 33,992 49.080 13.461$1. 748, 911.J-7 --PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments to Reconcile Net Income to Net Cash from operating Activities: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits changes in Certain Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies other Property and Investments Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement changes in Other Assets changes in Other Liabilities Net Cash From Operating Activities $ 41,060 85,896 75,659 (1,791)(3,737)996 (419)25,629 (11,296)(85,190)2,215 (6,928)122.094$ 57,759 80,245 (17,751)(1,791)21,405 (589)(2,809)(55,319)16,491 51,987 (9,120)9.351 149,859 S 66,663 76,418 25,453 (1,791)(28,826)677 7,994 89,330 (16,821)(36,798)(15,063)4,482 65.6193 165.615 INVESTING ACTIVITIES: Construction Expenditures Proceeds from Sale of Property other Items Net cash used For Investing Activities 963 (88.402)FINANCING ACTIVITIES: Issuance of Long-term Debt Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on cumulative Preferred stock Net cash From (used For)Financing Activities 187,850 (106,000)(36,982)(67,368)(213)(22,713)(124,520)(359)(124,879)(20,000)41,967 (52,240)(213)(30, 486)(176,851)(176.851)105,625 (20,000)1,951 (68,000)(212)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 10,979 5.795$1 6977 (5,506)11.301 8,128 3 .173 SL==I~i supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $38,620,000, $38,250,000 and$33,732,000 and for income taxes was ($38,943,000), $38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively. See Notes to Financial statements beginning on page L-1.J-8 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) $ 399.247 $480.240 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: Cumulative $100 par value authorized redeemable at the option of PSO upon 30 days notice.Call Price December 31, Number of shares Redeemed Series 2002 Year Ended December 31, 2002 2001 2000 Not subject to Mandatory Redemption: 4.00% $105.75 6 -25 4.24% 103.19 ---TRUST PREFERRED SECURITIES PSo-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of PSO, 8.00%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Less Portion Due Within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION see Notes to Financial Statements beginning on page L-1.shares 700,000, Shares outstanding December 31. 2002 44,600 8,069 4,460 807 5.267 75.000 298,079 47,358 200,000 (100.000)445.437 4,460 807 5. 267 75.000 297,772 47,357 106,000 (106. 000)345.129 J-9 --PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Lona-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 6.25 2003 7.25 2003 7.38 2004 6.50 2005 7.38 2023 unamortized April 1 July 1 December 1 June 1 April 1 Discount S 35,000 65,000 50,000 50,000 100,000 (1.921)S29Bs29 S 35.000 65,000 50,000 50,000 100, 000 (2 228)Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) % Rate Due (a)i 2002 (b) 2032 TOTAL December 31.2002 2001 (in thousands) November 21 S -S106,000 December 31 200 000 -520 00M 16 0 (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was $2.775%.(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) Rat Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 -December 1 S 1,000 S 1,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total$100,000 50,000 50,000 1,000 346. 360 547, 360 (1.923)545 437 Oklahoma Development Finance Authority (ODFA): 4.875 2014 -June 1 Red River Authority of Texas: 6.00 2020 June 1 Unamortized Discount Total i 33,700 33,700 12,660 12,660 (2) (3),Al 3-58 547 357 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of PSO.J-1 0 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Index to Combined Notes to Consolidated Financial Statements The notes to PSO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to P50. The combined footnotes begin on page L-1.combined Footnote Reference significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Benefit Plans Note 14 Business segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric utility Plant Note 28 Related Party Transactions Note 29 J-1 1 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiary as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 J-12 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements LOSS on Reacquired Preferred stock Earnings Applicable to Common stock$1,084,720 942.251 142,469 (309)59,168 82,992 82,992 229 Year En 2001$1,101,326 955,119 146,207 741 57, 581 ided December 31, 2000 (in thousands) $1,118,274 $989.996 128,278 3,851 59,457 _1999 971,527 824,465 147,062 (1,965)58,892 86,205 (3,011)83,194 229----1998$ 952,952 802,274 150,678 2,451 5,9135 97,994 97,994 705 89,367 72,672 89,367 72,672 229 229$ 8J39& U$ 72,443_$ --- a33 December 31, 2002 2001 2000 (in thousands) 1999 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$3,596,174
- 1. 697. 338$2 2S L67I5$ 380,663 (53,683)334,789$3,460,764
$3,319,024 $3,231,431 1,550,618 1,457,005-$i Q0,146 $1&862019$L380,616 $ 380,663$ 380,663 $ 380,663 1.384.242 ,2 16762:$ 380,663 283, 546 1998$3,157,911 1.317.057-£2 IQ -85A'25$ 380,663 296, 581$_677L244 308,915 293,989 S$_&6W5i8 $-6!A.-5i2 S-664,ZO0.11 1 LQ1 $ 4,70-1~ 2QTrust Preferred securities Long-term Debt (a)Total capitalization and Liabilities $__11O0,Q $ 110,000 A11 4 QQ00£_lUXlQQQ_$__M-t645 S& 6A45,963 A15&£$Z2 0-8,M~z$2,3Q0,676 $ 2 58 3&5102 6,162$2 Q8Z,258 (a) Including portion due within one year.K-1 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing activities are conducted on SWEPCo s behalf by AEPSC.SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. Results of Operations In 2002, Net Income decreased $6.4 million or 7% primarily resulting from reduced margins.In 2001, Net Income increased $16.7 million or 23% resulting primarily from the favorable impact of our sharing in AEP s power marketing activities for a full year.Changes in Operating Revenues Operating Revenues decreased 2% for 2002 primarily due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation ($12.6 million) and the positive impact of the interchange cost reconstruction (ICR) adjustments (see Note 6).In 2001, Operating Revenues decreased $17 million or 2% resulting from unfavorable wholesale marketing and trading conditions. Changes in Operating Expenses Increase (Decrease) From Previous Year (dollars in millions)2002 2001 Amount % Amount X S(69) (15) S(41) (8)26 143 (40) (69)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 26 165 18 10 (8) (10)2 19 12 7-(1)3 3 15 14 (1)(8)(1)(20)(1)2 16£LI)4 60 (4)Increase (Decrease) From Previous Year (dollars in millions 2002 2001 Amount % Amount %wholesale Electricity* $(25) (4) S(21) (3)Energy Delivery* 15 5 (12) (3)Sales to AEP Affiliates .7) (9) 16 26 Total operating Revenues £-1Z) (2) ILU) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Fuel expense decreased in 2002 due to a reduction in MWH generated and a decrease in the cost of fuel, primarily natural gas.Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. K-2 L.In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was mainly due to reduced prices caused by decreased electricity demand.The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in 2002 by$4.3 million. Other Operation expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other Operation expense increased also as a result of the Dolet Hills mining operation in June 2001.The 10% decrease in Maintenance expense in 2002 is primarily a result of higher storm and tree trimming related expenses in 2001.The increase in Depreciation and Amortization expense in 2002 is primarily due to the addition of Dolet Hills in June 2001, which added $3.0 million of additional expense in 2002. Depreciation and Amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income. In 2001, the increase in income tax expense was primarily due to an increase in pre-tax income.K-3 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES$ 664,185 348,236 72,299 1.084,720 388,334 44,119 42,022 189,024 66,855 122,969 55,232 33,696 942.251$ 689,085 333,004 79,237 1.101.326 457,613 18,164 15,858 171,314 74,677 119,543 55,834 42,116 955.119$ 710,200 344,950 63,124 1.118.274 498,805 58,518 13,338 159,459 75,123 104,679 53,830 26,244 989, 996 OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 NONOPERATING EXPENSES 1,797 4,512 3,229 542 5,487 3,112 (1,476)NONOPERATING INCOME TAX EXPENSE (CREDIT)1,772 INTEREST CHARGES 59.168 57, 581 59.457 NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 229 S 82.e763 229 S 89,138 229 S 72.443 Consolidated Statements of Comprehensive Income 2002 Year Ended December 31.2001 2000 (in thousands) --- ---NET INCOME $82,992 $89,36 OTHER COMPREHENSIVE INCOME (LOSS): cash Flow Power Hedges (48) -Minimum Pension Liability (53.635) -COMPREHENSIVE INCOME "24.309 S___36 The common stock of SWEPco is owned by a who77y owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.7$72,672$72 f92 K-4 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31, 2002 2001 2000 (in thousands) BALANCE AT BEGINNING OF PERIOD NET INCOME$308,915 82,992 DEDUCTIONS: cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$293,989 $283,546 89,367 72,672 74,212 62,000 229 229$ 3C&4915 $s91I9&9 56,889 229 The common stock of SwEPCo is owned by a wholly owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.K-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and cash Equivalents Accounts Receivable: Customers Affiliated Companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financia7 statements beginning on page L-1.$1,503,722 575,003 1,063,564 378,130 75,755 3,596,174 1.697. 338 1.898.836 5,978 5,119 2,069 62,359 19,253 (2,128)61,741 33,539 2,865 4,388 17,851 201.937 49,233 47. 572$2,20,65$1,429,356 538,749 1,042,523 376,016 74.120 3,460,764 1.550.618 1.910,146 43.000 24,508 5,415 43,133 12,069 (89)52,212 32,527 8,839 30,139 18,716 202.961 52. 308 67, 753$2,300,676 K-6 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CAPITALIZATION AND LIABILITIES December 31.2002 2001 (in thousands) CAPITALIZATION: Common stock $18 Par value: Authorized 7,600,000 Shares Outstanding 7,536,640 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo Long-term Debt TOTAL CAPITALIZATION $ 135,660 245,003 (53,683)334,789 661,769 4,701 110,000 637.853 1.414.323 78.494$ 135,660 245,003 308.915 689,578 4,701 110,000 494,688 1. 298.967 40,109 OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year Advances from Affiliates, net Accounts Payable General Accounts Payable Affiliated Comp;Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Cont over-recovered Fuel other TOTAL CURRENT LIABILITIES ani es 55,595 23,239 62,139 58,773 20,110 19,081 17,051 3,724 17,226 34, 565 311.503 racts 150, 595 117,367 71,810 37,469 19,880 36,522 13,027 36,297 5,487 26,074 514.,528 369.78 48.714 13.,127 15,45S0 DEFERRED INCOME TAXES 341.064 DEFERRED INVESTMENT TAX CREDITS 44,190 REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 1.806 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$2,208,675 2LINJ7U K-7 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments to Reconcile Net Income to Net cash Flows From Operating Activities: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts Changes in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accounts Payable Taxes Accrued Transmission coordination Agreement Settlement Fuel Recovery change in other Assets change in other Liabilities Net cash Flows From Operating Activities $ 82,992 122,969 (3,134)(4,524)$ 89,367 119,543 (31,396)(4,453)(1,151) (10,695)(24,371)(10,541)11,633 (17,441)17,713 24,257 12.16 210.563 (11,447)(19,578)(34,489)25,298 34,423 1,323 11, 714 169.610 S 72,672 104,679 14,653 (4,482)7,795 (1,254)22,103 43,962 (13,150)(24,406)(38,357)54,414 (37.001)201.628 INVESTING ACTIVITIES: Construction Expenditures Purchase of Dolet Hills Mining operations other Net cash Flows used For-Investing Activities (111,775)1.134 (110.641)FINANCING ACTIVITIES: Issuance of Long-term Debt Redemption of Preferred stock Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents Cash and Cash Equivalents January 1 cash and cash Equivalents December 31 198,573 (150,595)(94,128)(56,889)(229)(103,268)(3,346)5.415 (111,725)(85,716)(411)(197.852)(595)106,786 (74,212)(229)31.750 3,508 1.907 (120,671)446 (120.225)149,360 (1)(45,595)(124,074)(62,000)(229)(82.5 39)(1,136)3.043 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000 and$51,111,000 and for income taxes was $60,451,000, $49,901,000 and $27,994,000 in 2002, 2001, and 2000, respectively. See Notes to Financia7 statements beginning on page L-1.K-8 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) S 661.769 $ 689.578 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 1,860,000 call Price December 31, Number of shares Redeemed series 2002 Year Ended December 31E 2002 2001 2000 Not subject to Mandatory Redemption: 4.28% $103.90 ---4.65% $102.75 ---5.00% $109.00 --12 Shares Outstanding December 31. 2002 7,386 1,907 37,715 TRUST PREFERRED SECURITIES SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of SWEPCo, 7.875%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financial statements beginning on page L-1.740 190 3.771 4.701 110.000 315,420 179,183 198,845 (55.595)637. 853 11_41Mv23 740 190 3. 771 110.000 315,449 179,834S 150,000 (150. 595)494.688 K-9 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2002 2001 (in thousands) % Rate Due 6-5/8 2003 7-3/4 2004 6.20 2006 6.20 2006 7.00 2007 7-1/4 2023 6-7/8 2025 unamortized February 1 June 1 November 1 November 1 Se tember Juqy 1 October 1 Discount S 55,000 40,000 5, 505 1,000 I 90,000 45,000 80 000 (1.085)S315-420 S 55,000 40,000 5,650 1,000 90,000 45,000 80,000 (1.201)Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. % Rate Due 4.50 2005 July 1 (a) 2002 March 1 Unamortized Discount December 31, 2002 2001 Otiw thousandcs-) S200,000 S --150,000_. 198;85 5) 0OO (a)A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.311%.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2002 2001 (in thousands) % Rate Due DeSoto County: At December 31, 2002 future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 55,595 52,885 200,595 6,520 90,450 287.695 693,740 (292)S69344 7.60 2019 January 1 S 53,500 Sabine:$ 53,500 6.10 2018 April 1 Titus County: 6.90 2004 -November 1 6.00 2008 -January 1 8.20 2011 August 1 81,700 81,700 See Note 25 for discussion of Trust Preferred Securities issued by a wholly-owned statutory business trust of SWEPCo.12,290 12,290 12,620 13,070 17,125 17,125 Unamortized Premium SIZR-183 S 179-,3A K-10 i-SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to SWEPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to SWEPCo.The combined footnotes begin on page L-1.Significant Accounting Policies Extraordinary Items and Cumulative Effect Goodwill and other Intangible Assets Merger Rate Matters Effects of Regulation Customer choice and Industry Restructuring commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and Sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 K-1I INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generallyaccepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 K-12 COMBINED NOTES TO FINANCIAL STATEMENTS Index to Combined Notes to Financial Statements The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 2. Extraordinary Items and Cumulative Effect AEP, APCo, CSPCo, OPCo, SWEPCo, TCC, TNC 3. Goodwill and Other Intangible Assets AEP, SWEPCo 4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC, TNC 5. Nuclear Plant Restart AEP, I&M 6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC 7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 8. Customer Choice and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo, TCC, TNC 9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 11. Sustained Earnings Improvement Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 12. Acquisitions, Dispositions and Discontinued AEP, OPCo, SWEPCo, TCC, TNC Operations
- 13. Asset Impairments and Investment Value AEP, APCo, CSPCo, I&M, KPCo, OPCo, TCC, TNC Losses 14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 15. Stock-Based Compensation AEP 16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 17. Risk Management, Financial Instruments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo and Derivatives PSO, SWEPCo, TCC, TNC L-1
- 18. Income Taxes 19. Basic and Diluted Earnings Per Share 20. Supplementary Information
- 21. Power and Distribution Projects 22. Leases 23. Lines of Credit and Sale of Receivables
- 24. Unaudited Quarterly Financial Information
- 25. Trust Preferred Securities
- 26. Minority Interest in Finance Subsidiary
- 27. Equity Units 28. Jointly Owned Electric Utility Plant 29. Related Party Transactions
- 30. Subsequent Events (Unaudited)
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP AEP, APCo, CSPCo, I&M, OPCo AEP AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, PSO, SWEPCo, TCC AEP AEP* CSPCo, PSO, SWEPCo, TCC, TNC AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP L-2
- 1. Significant Accounting Policies: Business Operations AEP s (the Company s)principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP s eleven domestic electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC, are SEC registrants.
AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent, other commodities in the United States and Europe. In addition,theCompanysdomestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.International operations include supply of electricity and other non-regulated power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale.The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. See Note 13 for further discussion of changes in our communications related business and other business operations announced in 2002.Rate Regulation AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated bythe authorities of that country and are generally subject to price controls.Principles of Consolidation AEP s consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially controlled subsidiaries. The consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC include the registrant and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income forAEP and nonoperating income for the registrant subsidiaries. Basis of Accounting -As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71,"Accounting for the Effects of Certain Types of Regulation, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia byAPCo in June 2000, in Texas byTCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8, "Customer Choice and Industry Restructuring for additional information. Use of Estimates -The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates. L-3 Property, Plant and Equipment Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses. Plants are tested for impairment as required under SFAS 144. See Note 13.Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization -AFUDC is a noncash, nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. The amounts of AFUDC for 2002, 2001 and 2000 were not significant. Effective with the discontinuance of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia, West Virginia and other non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized were not material in 2002, 2001, and 2000.Depreciation, Depletion and Amortization -Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, otherthan coal-mining property, and is calculated largely through the use of composite rates by functional class as follows: Functional Class of ProDertv Production: Steam-Nuclear Steam-Fossil -Fi red Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Annual Composite Depreciation Rates Ranges 2002 2.5% to 3.4%2.6% to 4.5%1.9% to 3.4%1.7% to 3.0%3.3% to 4.2%1.8% to 9.9%Annual Composite Depreciation Rates Ranges 2001 2.5% to 3.4%2.5% to 4.5%1.9% to 3.4%1.7% to 3.1%2.7% to 4.2%1.8% to 15.0%Annual Composite Depreciation Rates Ranges 2000 2.8% to 3.4%2.3% to 4.5%1.9% to 3.4%1.7% to 3.1%3.3% to 4.2%2.5% to 7.3%L4 The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which were as follows: Nuclear Steam Hyd ro Transmission Distribution General AEGCo APCo CSPco I&M KPCo OPCo PSO SWEPCo TCC TNC 3.4 2.5 3.5%3.4 3.2 4.5 3.8 3.4 2.7 3.4 2.6 2.8 2.9 3.4 2. 7 1.9 2.2 2.3 1.9 1.7 2.3 2.3 2.7 2.3 3.1 3.3 3.6 4.2 3.5 4.0 3.4 3.6 3.5 3.3 2.8%3.1 3.2 3.8 2.5 2.7 6.3 4.7 4.0 6.8 Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages. These costs are included in the cost of coal charged to fuel expense for coal used by utility operations. Current average amortization rates are $0.32 per ton in 2002,$3.46 per ton in 2001 and $5.07 per ton in 2000.In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in 2002.Cash and Cash Equivalents -Cash and cash equivalents include temporary cash investments with original maturities of three months or less.Inventory Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market.Materials and supplies inventories are carried at average cost.Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be carried atfairvalue until December31,2002, and inventory purchased from October 26 through December 31, 2002 was carried at the lower of cost or market. Effective January 1, 2003, all natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held in connection with trading operations by approximately $39 million. This change will be accounted for as a cumulative effect of a change in accounting principle. Accounts Receivable AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for certain non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreementwith a group of banks and commercial paper conduits. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the companys balance sheet. See Note 23 for further details.Foreign Currency Translation -The financial statements of subsidiaries outside the U.S. which are included in AEP s consolidated financial statements are measured using the local currency as the functional currency and translated into U.S.dollars in accordance with SFAS 52 "Foreign Currency Translation .Assets and liabilities are L-5 translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on AEP s Consolidated Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual currency transaction gains and losses are recorded in income.Deferred Fuel Costs -The cost of fuel consumed is charged to expense when the fuel is burned.Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulators review and approval. The amount of deferred fuel costs under fuel clauses forAEP was $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "Effects of Regulation .We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings. This is also true for certain of AEP s Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 6, "Rate Matters and Note 8,"Customer Choice and Industry Restructuring for further information about fuel recovery.Revenue Recognition -Regulatory Accountinq -The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds)are recorded to reflect the economic effects of regulation by matching expenses with their recoverythrough regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period.Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made.When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.Traditional Electricity Supply and Deliverv Activities -Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and L-6 storage revenues also include the accrual of earned, but unbilled andlor not yet metered gas.Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133.Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves.Energy Marketinq and Trading Transactions In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps.We use the mark-to-market method of accounting for trading activities as required by EITF Issue No.98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net in revenues as unrealized gains and losses from mark-to-marketvaluations. When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. In October 2002, management announced plans to focus on wholesale markets around owned assets.All of the registrant subsidiaries except AEGCo participate in AEP s wholesale marketing and trading of electricity. For l&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash.Where this amount is recorded on the income statement depends on whether the contract s delivery points are within or outside of AEP s traditional marketing area. For contracts with delivery points in AEP s traditional marketing area, the total gain or loss realized in cash for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contracts with delivery points outside of AEP s traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income.Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP s traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP s traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP s traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis.The trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in AEP s revenues until the contracts settle. When these contracts settle, the net proceeds are recorded in revenues and reverse the prior cumulative unrealized net gain or loss.APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized L-7 gains and losses, as well as the net proceeds upon settlement, in nonoperating income.The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked-to-market based mainly on AEP-developed valuation models. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Such valuation adjustments provide for a better approximation of fair value. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with AEP-developed price models.As explained above, the effect on AEP s Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP s regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate. Construction Projects for Outside Parties Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue in proportion to costs incurred compared to total estimated costs.Debt InstrumentHedging and RelatedActivities In order to mitigate the risks of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges.There were no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17 'Risk Management, Financial Instruments and Derivatives for further discussion of the accounting for risk management transactions. Levelization of Nuclear Refueling Outage Costs -In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M s Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and 'ending with the beginning of the next outage.Maintenance Costs Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.See below for an explanation of costs deferred in connection with an extended outage at l&M s Cook Plant.Amortization of Cook Plant Deferred Restart Costs -Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and l&M.Other Income and Other Expenses Other Income includes non-operational revenue including area business development and river transportation, equity earnings of non-consolidated subsidiaries, gains on dispositions of L-8 property, interest and dividends, an allowance for equity funds used during construction (explained above) and miscellaneous income. Other Expenses includes non-operational expense including area business development and river transportation, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses.AEP Consolidated other Income and Deductions amortized over the life of the regulated plant investment. Excise Taxes AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement. December 31, 2002 2001 2000 (in millions)OTHER INCOME: Equity Earnings Non-operational Revenue Interest and Miscellaneous Income Gain on sale of Frontera Gain on sale of Retail Electric Provider Total other Income OTHER EXPENSES: Property Taxes and Miscellaneous Expenses Non-operational Expenses Fiber optic and Datapult Exit Costs Provision for Loss -Airplane Total other Expenses S 104 S 123 187 123$ 22 71 Debt and Preferred Stock Gains and losses 25 16 2 from the reacquisition of debt used to finance-73 -domestic regulated electric utility plant are 129 --generally deferred and amortized over the S 45 S- ___ remaining term of the reacquired debt in accordance with their rate-making treatment. If debt associated with the regulated business is S 142 S 68 5 28 refinanced, the reacquisition costs attributable to 179 56 49 the portions of the business that are subject to-49 -cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the-14 term of the replacement debt commensurate with S1321 s1&z L z their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to EP System follows the SFAS 71 are reported as a Loss on Reacquired ting for income taxes as Debt, an extraordinary item on the Consolidated lAccounting for Income Statements of Operations of AEP and TCC. See iility method, deferred discussion of SFAS 145 in New Accounting 'ded for all temporary Pronouncements section of this note for new book cost and tax basis treatment effective in 2003.Income Taxes -The AE liability method of accoun prescribed by SFAS 109, Taxes. Under the liat income taxes are provi differences between the I of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense.Investment Tax Credits -Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is included in interest charges.Where rates are regulated, redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistentwith the timing of its inclusion in rates in accordance with SFAS 71.L-9 Goodwill and Intangible Assets In June 2001, the FASB issued SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo.SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30,2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note 3 for further discussion of our components of goodwill and intangible assets.SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1,2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142.In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002.Nuclear Trust Funds Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers funds and to allow those funds to earn a reasonable return. In general, limitations include:.Acceptable investments (rated investment grade or above)* Maximum percentage invested in a specific type of investment
- Prohibition of investment in obligations of the applicable company or its affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115,"Accounting for Certain Investments in Debt and Equity Securities. Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liabilityaccount forthe nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.Comprehensive Income (Loss) -Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other, events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by L-1 0 -owners and distributions to owners.Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.Components of Other Comprehensive Income (Loss) Other comprehensive income (loss) is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income (Loss) for AEP.segment as viewed by the chief operating decision-maker. See Note 16, "Business Segments for further discussion and details regarding segments.Common Stock Options At December 31, 2002, AEP has two stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 15. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. No stock-based employee compensation expense is reflected in AEP s earnings, as all options granted under these plans had exercise prices equal to or above the marketvalue of the underlying common stock on the date of grant. The following table illustrates the effect on AEP s net income (loss)and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation , to stock-based employee compensation. Foreign Currency Adjustments unrealized Losses on Securities unrealized Gain on Hedged Derivatives Minimum Pension Liability December 31, 2002 2001 2000 (in millions)S 4 S(113) S (99)(2) --(16) (3) -(595) (c ) (4)Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of December 31, 2002 and 2001 is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the year ended December 31, 2000 was zero.Year Ended December 31, 2002 2001 2000 (in millions except per share data)$ (519) S 971 $ 267 components December 31, 2002 2001 (in thousands) Net Income(Loss), as reported Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro forma net income (loss)Earnings (Loss) per share: Basic as reported Basic pro forma Diluted as reported Diluted pro forma L__)5Th57) 5.3 0 (12)S-95 LZ34 cash Flow Hedges: APCO cSPco I&M KPCo oPco PSO SWEPCo TCC TNC Minimum Pension Liability: APCO cSPco INM KPCO oPco PSO SWEPCo TCC TNC S(1,920)(267)(286)322 (738)(42)(48)(36)(15)S (340)(3,835)(1,903)(196)S-UI5) S2Z97 SO. S3_____) SIZAZg OM18 S(70,162)(59,090)(40,201)(9,773)(72,148)(54,431)(53,635)(73,124)(30,748)Earnings Per Share (EPS) AEP calculates earnings (loss) per share in accordance with SFAS No. 128, "Earnings Per Share (see Note 19). Basic earnings (loss) per common share is calculated bydividing neteamings (loss) available to common shareholders by the weighted average number of common shares outstanding during the'-period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming Segment Reporting The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business L-1 I conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. Basic and diluted EPS are the same in 2002, 2001 and 2000.AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS.Reclassification Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts and Emerging Issues Task Force Topic D-43,"Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.39 .Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy.Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.New Accounting Pronouncements recent market transactions and cash flow projections. As a result of that testing, AEP determined that there was a net transitional impairment loss, which is reported as a cumulative effect of a change in accounting principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets.SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets.In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized. Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP s and SWEPCo s intangible assets.SFAS 143, "Accounting for Asset Retirement Obligations , is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured atfairvalue and is capitalized as part of the related assets capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest)will be recognized each period as an operating expense in the statement of operations. The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects l&M and TCC) and possibly other obligations. AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities.SFAS 142, "Goodwill and Other Intangible Assets, was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations. The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on L-1 2 In addition, the regulated transmission and distribution entities have asset retirement obligations related to the final retirement of certain transmission and distribution lines. There are also underground storage tanks located at various sites throughout the AEP System and PCB s are contained in certain transformer rectifier sets at power plants. The amounts relating to these obligations cannot be determined because the entities are not able to estimate the final retirement dates for these facilities. In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity from recording an expense for estimated costs associated with the removal or retirement of assets that result from other than legal obligations. The SEC Staff concluded that amounts that are included in accumulated depreciation related to estimated removal costs arising from other than legal obligations should be written off as part of the cumulative effect of adopting SFAS 143 unless the company is regulated under SFAS 71.Companies regulated under SFAS 71 may continue to include removal costs in depreciation rates but must quantify the removal costs included in accumulated depreciation as regulatory liabilities in footnote disclosure. The AEP registrant subsidiaries that are regulated entities have included estimated removal costs for non-legal retirement obligations in book depreciation rates.For non-regulated entities, including certain formerly regulated generation facilities, asset retirement obligations associated with wind farms, closure costs associated with power plants in the U.K. and possibly other items will be incurred.Also the amount of removal costs embedded in accumulated depreciation is expected to result in a favorable cumulative effect adjustment to net income. However, AEP and its registrant subsidiaries have not completed their determination of the net effect of these items on first quarter 2003 results of operations upon the adoption of the provisions of this standard.In August 2001, the FASB issued SFAS 144,"Accounting for the Impairment or Disposal of Long-lived Assets which sets forth the accounting to recognize and measure an impairment loss. This standard replaced, SFAS 121, "Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of. AEP adopted SFAS 144 effective January 1, 2002.The adoption of SFAS 144 did not materially affect AEP s results of operations or financial conditions. See Notes 3 and 13 for discussion of impairments recognized in 2002 by AEP and its registrant subsidiaries, affected by SFAS 144.In April 2002, the FASB issued SFAS 145,"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections'. SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. In 2003, for financial reporting purposes AEP and TCC will reclassify extraordinary losses net of tax on TCC s reacquired debt of $2 million for 2001.In October2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17 (EITF 02-3). EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by generally accepted accounting principles. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts entered into and inventory purchased through October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus will be reported as a cumulative effect of an accounting change. Such contracts and inventory will continue to be accounted for at fair value through December 31,2002. Energycontracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133.L-1 3 Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses.Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows.Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. Unrealized gain or loss at inception is recognized only when the fair value of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts. In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entitys commitment to an exit plan.SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value.The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.In November 2002, the FASB issued Interpretation No. 45, "Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No.34. The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition. See guarantee details discussed in Note 10.In December 2002, the FASB issued SFAS No.148, "Accounting for Stock-Based Compensation-Transition and Disclosure , which amends SFAS No. 123, "Accounting for Stock-Based Compensation .SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Underthe fair value based method, compensation cost for stock options is measured when options are issued. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation. SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options.In November2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation: A Comparison of FASB L-14 Nuclear Operating Company South Teas Procca Elecric Gcnerating Stailon PO. Box 28.9 Wdsworth, Texs 77483 September 29, 2003 NOC-AE-31659820 STI No.: 0300161 7 File No.: G20 1 OCFR50.71 (b)U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 South Texas Project Units 1 and 2 Docket Nos.: STN 50-498; STN 50-499 Annual Financial Reports Pursuant to the requirements of 1 OCFR50.71 (b), STP Nuclear Operating Company acting on behalf of itself and for AEP Texas Central Company, the Austin Energy, City Public Service of San Antonio, and Texas Genco, LP (formerly: Reliant Energy), submits the attached current annual financial data for the South Texas Project Electric Generating Station.Should you require additional information, please contact Karen Wheaton at (361) 972-8698 or Ron Hyde at (361) 972-7992.Ron G. Hyde Supervisor, Corporate Insurance KMW Attachments: a) AEP Texas Central Company Annual Report b) AEP Texas Central Company Form 1 0-K c) Austin Energy Annual Report d) City Public Service of San Antonio Annual Report e) Texas Genco, LP Annual Report f) Texas Genco, LP Form 1 0-K g) STP Nuclear Operating Company Financial Statement pwq0)O:\HUMtANRESOURCES\INSURANCE\ANNUAL MUST DOS\2003\NRC-ANNUAL FINANCIALS (2003).DOC STP Nuclear Operating Company cc: (paper copy)NOC-AE-31659820 File No.: G20 Page 2 (electronic copy)Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011 -8064 U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Richard A. Ratliff Bureau of Radiation Control Texas Department of Health 11 00 West 49th Street Austin, TX 78756-3189 Jeffrey Cruz U. S. Nuclear Regulatory Commission P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 A. H. Gutterman, Esquire Morgan, Lewis & Bockius LLP L. D. Blaylock City Public Service David H. Jaffe U. S. Nuclear Regulatory Commission R. L. Balcom Texas Genco, LP A. Ramirez City of Austin C. A. Johnson AEP Texas Central Company Jon C. Wood Matthews & Branscomb C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 F. H.G.R. G.R. D.S. C.RMS File Mallen, w/o Harrison, w/o Hyde, w/o Piggott, w/o Beaver N5001 N5001 N5001 N5014 N5014 N2002 AAERiICAN t ELECURJ I FP3Wly t r I r I v , I : .,-r, Ir-iiil'I i -i rwjrr I 2/'a 313/4Ic'I \ 2002 -2001 C h a n g&-Net Income (Loss) (in millions) .ongoing ' -- ---~~$95.7 $1,087-, as reported'. (519) -S(l19 $971 (153.50 Earnings (Loss) Per Share *- -, --ngoing -- .-.. -S89$3.38: -(4~as reported -11 57] $3.01 (1_2 Revenues o-(in billions) -$14 6 $12.8 -i.--~Cash Dividends -$2.40 $2.40,-Year*End Clos~~~ing Stock Price 527.33 $ 43.53 -(37 Book Value'at Year-End-- $20.85 $25.547-' ~ Total Assets (in billions):
- -. .$34.7 $39.3 U.S. Customers tat year-end) (in thousands)', 4,'975,. 4,930 0 Global Employment
--' 22,083 -2 3,4 (4.202rportedls f (.7 per share, adjusted fbr investmnent-Value and asset smpairmenits (33 07, p;er*- share), disposition and aSSEt iniPairmrents of SEEBOARD and CitiPo'wer (134 per share) sustainedean Ings improvement initiative restrncrurng costs ($0. 16 per share), asset impairments of Texas plants ($0.08 per share) and other items (10.04 per share), offset by~ a gain on disposition of Texas REPs ($0.23 per sharte), produces ongoing earigs of $2.89 peshae 201rpred earnings of $3.01 per share. adjuste for merger costs ($0.05 per share), neofo oso Pipe Line-related Enron purchase obligations ($0.08 per share), Severance accruals ($9.08 per share), nonre--curring adjustment ~~for taxes other than PIT, ($0.04 per share), disposition andwrt-onf assets -($0.01 -_per share) and an-extraordinary loss from discontinuance of regulatiyacontn firgene&ration in certain, stares ($0. 16 per share), offset by. the cumulative effect ofSA 3ransitoajumet(05) pdu es: -ongoing earnwg of $3.38 per shae .-- ..Thsdisso inldsfradloigsaeet ihin the mening of Section 2lEof the Secursies--- Exchangze Act of. 1934. These forward-looking statemnents reflect assumptions and involve a number of risks: aduncertainties. Amiong the factors, both foreign and domestic, that could cause, acnual results to differ materiallyfrom forwvard-looking statements are: electric-load andl customer growth;, abnormnal weather ri-coditions; aiva-ilable sources -of and prices kii 6oal'and gas;_ availability ofgenerating capacity; risks related &to energy trading and contrctiont under contract; the speedl and degree to which comeiinisitoued -- to our power generation business; the stiuceure and timing of a compedtitive market~ for 'electricity and its imat on prices; the abili ty to recover net regulitory assets,'other stranded costs and implementation coats-in c'onnection'with deregulation of generation in certain states; thetirniing of the im-pl'einmntstiois of AEP-'s '-resructurng plan, new legislation and government regulations; the ability to suiccessfully control costs; the ----success.o e business ventures;: international developments affectinm u oeg netet; h economic clitnAlre and growthi in our service and trading 'territories,' both dlomestic and fiorerign; th'e ability --of the, compansy to comply, with, and to successfly. c aln~reenvironmental regultions and tosuc- T cessfulfly litigate claims that the comjpn iltdteCta n rAc;inflsti6iary rns litigation con- --cerniuig _AEP'smn'erger wihCSW; changes in electricity and gas miia et prices' n neetrts lcutos in foreign currency exchange rates, and other risks and unforescen events. ---. 4
ast year was extremely -difficult for AEP. Due to a variety of factors, our earn-ings fell dramatically, as did our stock price. We deeply regret that our performance was far below our goals and your expectations. In response to the negative developments in 2002, we are taking decisive steps to strengthen our bal-ance sheet and put the company back on track for value growth. We remain dedicated to providing low-cost electricity, superior customer service and an attractive return to investors. A look back: Disappointing results Our utility operations performed reasonably well in 2002 despite rising costs, but the withering of wholesale markets in the U.S. and abroad cut into earnings from our wholesale operations. As I'm sure you're aware, the wholesale arena -including power generation, associated assets and related marketing activity -had been highly profitable for us the past couple of years.AEP's ongoing earnings totaled $2.89 per share in 2002 compared with $3.38 in 2001. As-reported earnings were negative $1.57 per share, down from $3.01 the previous year.-r. Q mu. Writing down the value of poorly performing investments contributed to charges of approximately $1.5 billion for 2002. Some of these write-offs, such as those related to telecommu-nications assets, were anticipated. Others, such as a $415 million charge related to our generation assets in the United Kingdom, were not. We also incurred an equity reduction of nearly$600 million because of lost value in our pension plan assets. While the latter event lowered the equity on our balance sheet, the other items also reduced the earnings on our income statement. On the positive side, despite last year's very tough market, we strengthened our balance sheet by $2 billion. We did it by selling non-core assets and issuing additional common stock and equity units. In 2002 we completed the sale of SEEBOARD, a regional electric company in the UK, and CitiPower, an Australian electricity provider. AEP's first visit to the equity market in 20 years occurred last spring.Cash proceeds of approximately $1.1 billion from thei asset sales and $990 million from the issuance of common stock and equity units were used to pay down debt.We did not attain our capitalization goal for 2002 of 45 percent equity and 55 percent debt but we expect t o-make significant progress this year. 2002 Sharehb Our long-term goal is 50 percent to 55 percent debt.A look ahead: Focus on the basics In 2003, we will focus on the basics. We are returning to a more traditional model of a regulated utility with a small commercial group dedicated to maximizing the value of .our generation fleet, which is the largest in the United States.S&P Electric A Currently, we think AEPs traditional utility Utlity Index business 1will perform at roughly the same ............... level as last year and the wholesale business will have a somewhat weaker year. We project 2003 ongoing earnings in the range of $2.20 to $2.40 per share, including the dilution from additional equity issued in this year's older Return executive management will not be paid 0 this year. In addition, we expect to pare our-5 capital expenditures forecast for this year by to $200 million, to $1.5 billion..,i,:* -15: I .;I......EP CL cE: E-c q: _CA: E0:E-E o --o a si::;.w:¢: 0..X.,-.T :0 E f: first quarter.* O Our decision to recommend a reduction in the quarterly dividend of about 40 percent......... -25 E: to our Board of Directors came after consid--30 erable analysis andw as painful but neces-sary. Reducing the dividend to a quarterly rate of 35 cents per share, starting with the.40 : J, 0 Vsecond quarter, will result im annual cash S&P lndex ;savings of $340 million. This will imrnmedi-............. ately improve retained earnings and create free cash flow to boost liquidity and pay down debt. We believe the dividend will still have significant value and produce an attractive yield.We began shedding assets to improve our balance sheet last year and anticipate that process will accelerate in--2003. Non-core assets are the most likely candidates for divestment. This will be an orderly disposition. Proceeds-will go toward debt reduction.
Our liquidity position is strong. We have $3.5 billion available in cash and credit facilities, and we had $1.2 billion in cash at the, end of last year. During 2003, we expect free cash flow of approximately
$130 million after i .i : .: :: i 0 E -: ..,:: i:: E i : -: E -i i~ ~ ~ ~ ......E .....-i .E dividends are paid.- -In 2003, we aim for year-end capitalization consistent with a strong&BBB rating. We will continue to seek To bolster our balance sheet, we plan to lower costs,.. reduce the quarterly dividend, dispose of additional non-core assets, maintain our liquidity and current lines of credit,'and maximize cash flow.A company-wide cost reduction program should result in sustainable net savings in operations and maintenance costs of approximately $60 millhon when compared with 2002 actual expenditures, and more than $300 million when compared with previously projected 2003 expendi-tures. We reduced our work force by approximately 1,300 positions. Based on 2002 performance, bonuses for senior opportunities for further debt reduction and to work with the rating agencies to ensure we're addressing their concerns.:.: With deregulation at a standstill in much of our service area,.we are re-evaluating our corporate separation initiative. The legal separation of our regulated and unregulated businesses is provided for in Texas and Ohio,_where generation is deregulated and customers in most areas are able to choose their electricity supplier.However, the cost savings and benefits for all customers of a company-wide separation are now uncertain. We are exploring these issues with our regulators. Our intent is to comply'with restructuring legislation in the states that provide for a legal separation and to maintain a functional: separation elsewhere.-- w 1 1-state service territory, thanks in part to increased usage by residential customers. AEP's Texas operations were a major contributor to last year's utility-related earnings improvement. Customer ::`choice was introduced in January 2002 in most-areas of our Texas service territory. AEP's obligation to supply .retail electric providers (REPs) in that state last year con-tributed $495 million to gross margin. Sale of our affiliat-ed REPs to Centrica, a leading retail energy provider, near the end of 2002 provided immediate cash proceeds of:$146 million. The transaction includes an arrangement through 2006 that allows AEP. to share in any increased earnings opportunities that develop in the Texas retail*market, protecting us against downside exposure.Even with deregulation stalled, many of the nearly 5 mil-lion customers linked to our Wires will benefit from rate freezes in their respective states for the next severlS years.: Utility operations: Stable, predictable AEPs regulated operations generate stable, reasonably predictable revenue and earnings. They have been a steady contributor to our performance all along. The mission of our regulated business unit is to provide safe,: cost-effective and reliable service to customers. Ongoing earnings from utility operations in 2002 totaled$326 per, share, up from $39in 2001. Retail gross -margins rose $250 million in Texas, $178 million in Ohio and $91 million in other jurisdictions throughout AP's Transmission represents a significant piece of our regulated business. AEP, following Federal EnergyRegulatory Commission (FERC) guidance, continues working toward transferring functional control of its 38,000-mile transmission network to regioa transmis-sion organizations, or RTOs. -.-You may recall that AEP was among the companies deeply involved in recent years in developing a proposed for-profit RTO called the Alliance. Last spring, however, 3 FERC turned down our proposal, so we are pursuing affil-lation with PJM Interconnection for our eastern assets and the Midwest Independent System Operator in the west, 'At this point, we don't anticipate divesting our transmis-. sion assets. We project RTO-related costs of $30 million i.to $40 million in 2003.
- 1 0 0 0 0-c U)0 a 0.0 S S U)N C 0 N S 0 0.U U S'Li S U E Wholesale investments:
Unmet expectations Our unregulated operations performed well below our projections in 2002. AEP's wholesale investments lost$45 -million or 13 cents per share. Some of these investments, such as our natural gas and barge-line holdings, contributed positively to earnings, but the UK generation we acquired in 2001 -the Fiddler's Ferry and Ferrybridge plants -posted a $59 million operating loss.The UK has proved to be a very disappointing and difficult market. The oversupply conditions worsened as the year progressed, particularly after the British gov-'ernment decided'to subsidize British Energy. The $415 million write-down of UK generation that I mentioned earlier. stems, from recent analyses showing that UK power prices won't recover to levels that will support the carrying value of the plants on our books at the original purchase price of roughly $1 billion.As I noted above, we will be looking to divest certain wholesale assets and the UK generation certainly will be considered. An even greater loss is possible in the UK in 2003. We're evaluating the best way, to reduce earnings drags and preserve shareholder value in this investment.l E Other unregulated investments not related to our whole-sale business also fired poorly and are candidates for" i-divestment. Our telecommunications business had a $36.-million operating loss. We are actively seeking buyers for this business.Energy marketing: Asset focus.Most of the output of our generating units is committed to our retail customers. The rest is marketed to other utilities and wholesale customers. Our decision to greatly scale back our energy marketing and trading operations and concentrate on' optimizing the value of our assets is reducing our risk exposure and helping to preserve our creditrratings. Net margins from trading activities declined by'$349 million last year because of our reduced activity and because earnings from trading in 2001 were exceptionally strong. C The outstanding net fair; value of trading contracts has fallen from approximately $450 million to $250 millionA:0 over the past year. The average duration of our existing:- trading book is year-end 2003 for gas and second-half 2004 for power.--0 Our risk management group continues to work closely with the trading group to ensure limits are enforced.We reduced value-at-risk limits by 50 percent last year..Environmental: Compliance and beyond::: Coal-fired generation remains AEP's mainstay. At the end of 2002, our generating capacity mix was 69 percent coal and lignite, 20 p1ercent natural gas, 8 percent nuclear and 3 percent wind, hydro and other.Use of fossilf Eels brings with it environmental expendi-'tures, but our customer prices remain among the lowest'-`in the regions where we operate.: Our ongoing program to meet federal standards to con-trol nitrogen oxide emissions'will cost an estimated
- $1.3 'billion to $2 billion in capital expenditures.
AEP remains a leader in policy discussions and research to address environmnental concerns. .We are actively promoting enactment of legislation to 4 .further reduce sulfur dioxide, nitrogen oxide and mercury emissions to address air quality issues' associated withL::',- coal-fired generation. AEP is one of the founding' members of the Chicago Climate Exchange' the first voluntary pilot program for trading greenhouse gas emission credits.We've committed to reducing our greenhouse gas emis-: sions by4 percent over the'next four years. AEP also is:: participating in a project, led by Battelle to assess ,, 0 i, 2 E i, i X , ,;~~~~~~~ .; ........................ whether deep injection of carbon dioxide into the earth is a feasible climate-change mitigation technology. .:: Commitment to improve I want to thank our employees for their hard work during: these unsettling times in the power industry. Assets are: AEP's strength, and our employees are our strongest
- tS ..I : ... t i. A ---E.........i-
assets. Their dedication, talent and continued commit--ment to our business mission are at the heart of our plan'.~~ ~ ~ ~ ~~~~~~ .... ... .for recovery in the year ahead.:::
- - ..: -::-:: :. : Stepping up to new duties last 'year were Holly, Koep -who was named to oversee our unregulated businesses:
after the departure of Eric van der Walde; nd To ..m. .....Hagan, head of our shared services organization. Tomr: succeeded Joe' Vipperman, who retired last year after more than four decades of dedicated service.Last year was indeed difficult and 2003 also holds::many challenges. But I believe the measures I have outlined will improve our performance, and we are C'committed to doing what it takes to rebuild the value of your investment. E. Lin n Draper, Jr..Chairm~an, President &Chief Executive Officer February 28, 2003....i 7:: , f iESE-E::: .E : -. -:~ ~: 7 :: ; , 0:0 a, 0 C/) 2002 2001-Assets...Cash and Cash Equivalents .1224 -Energy Trading and Derivative Contracts Current ..104B ; 26 Other Current Assets:::...3,842L Property. Plant and Equipment 3ZA14 .Accumulated Depreciation and Amortization .-- 1,V3..q .... .......d.. .............. ............... ......... ....... ....Net Property, Plant and Equipment ...2,8 V0.............. ............. .............. ............. ......... ....Regulatory Assets 2,8 Other Assets ... ..Total .... .S24.741 Capitalization and Liabilities .. .Energy.Trading and Derivative Contracts Current:~. .$1,4$17 Other Current Liabilities 8,4 ..t4 Long-Term Debt .Deferred Income Taxes and Investment Tax Credits'47 Minoity Interest in Financing Subst iday .79 Other Liabilities ..34~a Total Liabilities Cumulative Preferred Stocks of Subsidiaries .14 0: Common Shareholders' Eqluity _______Total I .... 341 1 __ _E : Full disclosure 'of all Capitalization Ratio 2002 2001 o fina~ncial information o .~~~~~~~~~~~~~~0.7% .0.7%is included in the. '1 Long-Term De b-t Appendix A to the .....Proxy Statement. CiShort-Term Debt.0.U ~ ~ ~ ~ ~ Minority Equity ~~~~~~~~~~~~~~~~~~~~ 32.2% -49.3% 35.8% 42.8%~' referred Stock 32 F 14.4%..:~]:* 17.5%: ., , '- E .- , 7 -I ., -.7 11 I " I 1- : --I r --, 1 -1 , .,, P i --1: . I ...11 I E, n .. i. Revenues Expenses: Fuel and Purchased Eniergy Mainitenianceand Other Operation
- . .. .:::~~::~:
Non-Recoverable Merger Costs':, .:~~~~~~~~~~~............. ................ ..... ......Asset Impairments
- Depreciation and Amortization
.Taxes Othe r Than Income Taxes Total Expenses Other.Income ...Investment Value and Other.Imnpairment Losses Other Expenses...... Income Before Interest, Preferred Dividends. Minority Interest and Income Taxes Interest, Preferred Dividends and Minority Interest Income Taxes Income Before Discontinued Oprtin, xraordinary items and Cumu lative Effect Discontinued Operations -Income (Loss) (net of tax)Extraordinary Losses (net of tax):.: Discontinu'ance of Regulatory Accounting for Generation Loss on Reacquired Debt:-Cumulative Effect of Accounting Change (net of tax)Net Income (Loss)Average Number of Shares Outstanding.. Earnings Per Share: ~.. .....Income Before Discontinued Opraions,.~~~~~~~~~~~~~~~~~~~~~~~....... Extraordinary Items and Cumulative Effect..Discontinued Operationrs. Extraordinary Losses: 1.~:: .: ,w C umulIat i ve Effect Net Income (Loss)Cash Dividends Paid Per Sha're7::- TN.M.=Not Meaningful 2002 2001.S14,55 I $12,767 f-,6,307 4,944 3,710: 10 21 7 B67~~~~~~~~. .-1,377 ~ 1,243*718: 667: 13,292 10,585 445K! 335 321 -321 j 1 87-.1,66. 2 2,330 831; 867;214 ~546 21 917 (190) ~86.1 (48): (2)S (~1) I $ 971 i3~~: 322 2 85: 0:i.26 (0.16)I (¶.57r $ 3.01 S 2.4c~ $ .40...% Change: 1.7 N.m F S C)S C)C)-u 0 S M 0 0 C,)C..0 0.0 C,)0.0.0.: w.-...11 --I 7 -: I % -1 , -" 1, --., -, -I , 1, ..-_ .- --ly .-A .., -.Jll-1 , , ., -, -i -i i,, -, -1 ; 1. I I : ", 'zi , ,_, --, '_ 1 -, 1 -% I I .7 1 1 1, _; , -., t ----.1 __ --I 1- -2002 Operating Activities -: Net Income (Loss) M .591.;NtIcm Ls):f ; ::! ............. .... ..... .. ............... ........ ........... ... .... .... ..Plus: Discontinued Operations Loss (income)Net Income from Continuing Operations Depreciation and Amortization' -.. .: :.Asset Impairments Investment Value and Other Impairments ,I~~~~~~~ ............ .. .. .. .. .. .. .. .. .. ........ .................... .. .... .. .Adjustmrents for Other Noncash Items and Working Capita!l (3.. AjsmnsfrOhrNnahiesa dWrigCptl. -:. , ;................ ...... ........................................... I............. ... .wi : Net Cash Flows from Operating Activities i.,, ~ ~ ~ ~ ~ .... ...... ...... ....-.. .. .. .. ... .. .. ... .. .. .. ... .. .. .................... Investing Activities:. Construction Expenditures (1.. .... .................. .... ....................................................................................... .......Purchase of Gas Pipe Line Purchase of UK Generation Purchase of Coal Company:.............. ........................... ............................................ .......... ,......PurchaseofBargingOperations: .-: F.Purchase of Wind Generation:: Proceeds from Sale of Retail Electric Providers.~~~~~~~~~~~~~~. ..................................... ........Proceeds from Sale of Foreign Investments
- ................................
........... ..................................................................,i.i., : 1 ^ di : i:-Proceeds from Sale of U.S. Generation Net Cash Flows used for Investing Activities .E .,.,.,.,.,,,,.,.,,.,,,...,.,.,,,,............... .. ..............................- --i.. ..Financing Activities
- .Fnanin.Aciviie...........::.
- ....... .........
......................................... ............ .... ..11..-.'.....r. Issuance ofCommon Stock .:: I-ssuance of MinorityInterest ........................................... .. ...... ...... ..... ...... ...... ..... ...... ... .Issuance of Equity Unit Senior Notes I~~~~~~...................I........... ..... ............................... i^.......... .,,, .... ... .....Change in Long-term Debt (net)Retirement of Cumulative Preferred Stock~:;:liRetiementof~muitive~refrredtock-T .i;0i,,e.,..........I .................................................................. .............. .. fs, Change in Short-term Debt (net)-Cagihottrebne).,
- .0,..........
..... ............................................ ......... ., l......'.... Dividen'rds Paidon Coim'mon Stock .. ..> ,. ........K.! !..* -.*- *-- *--' ---- !*-- --- *'*- .* ---- -'5:: .................................... ......... ........ ........... .. ..... .. }}}. .Other::: t,.er.. .. .. ........... ............ I.............. .. ....Z_. ... ....Net Cash Flows from (used for) Financing Activities Effect of Exchange Rate Changes on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents from Continuiing Operations Beginning of Period Cash and.Cas Equivalents fo otnigOeain n fPro-:. ':Net Increase (Decrease) in Cash: and Cash Equivalents from Discontinued Operations:
- .5B -: :-; 'Cash and Cash Equivalents from DisContinued Operations
-eginning of Period Cash and Cash Equivalents from Discontinued Operations -End of Period._2001 E i.e.$+fl.:0t t:,]"jft'. N s T;eq;fsi:48-T w7S,:*--oll ,.S..:...m.:.(usi54-. t'1' 'f ,.g,...X, ffi;' a@t.¢ si ,,,1 b', ,=.;,. : ii ! .d... N.. _D.. -i-i _z Rl k i N I N 1 n i S: W., E.r d's is i "!] l t l:' a:.>i-r0,: 0.: U,,, C3g 0: 0 0.0 E:_E u)C" C 0`.0:.a.0.: 0 L i Ul~'E 4 srr:^ :? -:* 4:..': n ;e .i-To the Shareholders and Board of Directors:: of American Electric Power Company, Inc.:-: We have audited the consolidated balance sheets of::: American Electric Power Company, Inc.,,and its subsidiaries as of December 31, 2002 and 2001, and the related consoli-dated statements of operations, common shareholders'
- .E ---: -: .:E::---; :.-- i-::f i~~~~~~. ... .... .E.::EE;:
-....equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. -These consolidated financial statements and our' report thereon dated February 21, 2003, expressing an unqualified opinion (which are not included herein) are included in.. .:::: -: --:- -.:: :E :: .:E.:: -.~~~~~~~. ....: .E ~fiEi. .-.-... : Appendix A to the proxy statement for the 2002 annual meeting of.shareholders. The accompanying condensed~~~~~~~~~~~~~~~~~~~~~... .... .... .... .-.consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on such condensed consolidated financial statents in relation to the complete consolidad -.statements in relation to the complete consolidated
- -
- S The'management of American Electric Power Company,:.:
Inc., is responsible for the integrity, representations and objectivity of the information in the Company's sumrmary annual report and condensed consolidated financial state-ments. The condensed consolidated financial statements are derived from the consolidated financial statements included..in Appendix A to the proxy statement, which has been prepared in conformity with generally accepted accounting
- principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations.
The information in other sections of this summary annual report is consistent with these statements..T:::he consolidated financial statements have been audited by Deloitte & Touche LLP, from which these condensed consolidated financial statements have been derived and whose report appears on this page. The'auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported inancial condition and results of operations. Their audit includes procedures believed by them to provide reasonable ,:assurance that the financial statements are free of material::: misstatement and includes an evaluation of the Company's internal control structure over financial reporting.
- .: : .-: -wq -.: Chairman, President
&Chief Executive Officer .Chief Financial Officer: financial statements. In our opinion, the information set forth in the accom-:-:.:: -_ _.: _ :: ._ :: .:: ..:: : : _ :: :: :::::::_ .: : ::._......
- .:: ..::. :.. ::::-::::.
panying condensed consolidated balance sheets as of December 31, 2002 and 2001, and the related condensed consolidated statements of operations and of cash flows fort:-.. .--~~~~~~~~~~~~~~~~~~~~~~~..... the years then ended is fairly stated in all material respects in relation to the basic consolidated financial statements-.-'-...:s from which it has been derived.a..e: :, :1* .>B U m U.* -u a B 0 0 N, C0 0.......... ...S S J: ..~ ~ ~ ~~~~~~~~~~~ ~ ..... ..-_-~~~~~~~~~~~~~~~~w ..Columbus, Ohio February 21, 2003 Board of Directors: Front row letf to right Donald G.Smith, E.R. Brooks, E. Linn Draper, Jr.,John P. DesBarres, Robert W. Fri Bac row left to right.: Donald M. Carlton, William R.Howell, Linda Gillespie Stuntz, LeonardJ. Kujawa, Richard L.Sandor, Kathryn D. Sullivan .Thomas V. Shockley, 111, Lester A. Hudson, Jr.: Dr. E. Linn Draper, Jr., 61 .-Chairman, President& Chief Executive Officer: (1992) : E.R. Brooks, 65. -Retired Chairman.a & Chief Executive Officer, Central & South West Corp..Granbury, Texas (2000) .: Dr. Donald M. Carlton, 65 Retired President& Chief Exccutive Officer, Radian International, LLC.Austin, Texas (2000) .!N. .John P. DesBarres, 63 Investor/Consultante Park City, Utah : (997) LH.N.r Robert W. Fri 67: Visiting Scholar, Resources for the FutureL Washington, D.C.(1995)?7:7-m 0 0 U, 0.0 M..0 Co..0 LU 0 0C1 William R. Howell 67 Chairman Emeritus, J.C. Penney Company, Inc.Dallas, Texas (2000) .H.P Dr. Lester A. Hudson, Jr., 63 Professor of Business Strategy, Clemson University Greenville, South Carolina:':: (18)A-DJ : : i Leonard J. Kujawa, 70 International Energy Consultant Atlanta, Georgia:: (1997) D.'-Dr. Richard L Sandor, 61 Chairman & Chief Executive Officer, Environmnental Financial. Products, LLC Chcago, Illinois (2000) Drf~g Thomas V. Shockley, III, 57 Vice Chairran: (2000)Donald G. Smith, 67 Chairman, President& Chief Executive Officer, Roanoke Electric Steel Corp.Roanoke, Virginia (1994) N.?- -: Linda Gillespie Stuntz, 48 Partner-: Stuntz, Davis & Staffier, P.C.Washington, D.C.(1993) "- 'Committees of the Board: The chairman is listed in ().A Audit (Carlton),.
- Directors and Corporate Governance (Hudson),.-..
- Executive (Draper), Finance (Stunt), H Human Resources (DesBarres), N Nuclear Oversight (Sullivan),:
Policy (Fri)Dr. Kathryn D. Sullivan, 51 President & Chief Executive Officer, Center of Science & Industry Columbus, Ohio (1997) A N.r , --r 7 , -r -e, ...-, a "'. ---7 il , 4 4. 1 .I t- :, -i _- 7 -i'. -t! E i ., ... , %American Electric P-Service Corporatior ---I'ow nI:.. ~:: :. ---.. : ..: .-:.L :, : .-Office of the Chairman r Front row Iet to right: Holly K. Koeppel, E. Irnn Draper, Jr., Thomas M. Hagan, Susan Tomasky, Bac row lift to right: Robert P. Powers, Henry W. Fayne, Thomas V. Shockley, III American Electri Company. Inc.E. Linn Draper, Jr.Chairman, President Chief Executive Offi Thomas V. Shocklh Vice Chairman: c Power and Dy,Il Offic ce.Lito.icer E. Unn Draper, Jr.: Chairman, President and Chief Executive Officer Thomas V. Shockley, lli:Vice Chairman and-:'H : i;Chief Operating Officer Henry W. Fayne Executive Vice President Thomas M. Hagan --Eecutive Vice President -Shared Services Holly K. Koeppel Executive Vice President Robert P. Powers Executive Vice President -Generation -117 Susan Tomasky .:- --: Executive Vice President-Pollcy, Fiance and:.Strategic Planning, and::Assistant Secretary Melinda S. Ackerman:? Senior Vice President -Human Resources Nicholas J. Ashooh Senior Vice President-Corporate Communuications J. Craig Baker.Seniomor Vice President -Regulation and Public Polic IA. Christopher Bakken, III ,,.Senior Vice President .- -'Nuclear Operations i: .: ... .li .E:E ..... E i !-:iL i.ver;0-3 0:0:; i,0-f; -t,;.:: :: :::::::: :: : if -:::: -:- -,* :! i: i E i.: f i -. .:.f i-D:: :S.-..::: -:.:.-:00-S't.t -::::f:: ',,' i'-....t:' T-ttT, i i :000 'l::gE: :-:: if::-i E E i: ' ;'::"* ....:!g:-t,,-*: .i-:-. :i: [-... ...: -S-.E : i t! t :,.s ' f' ': E .f --i 0 ;$ tiE: 'i', t-;-,.,.-;fX,,,..,404 icye: ::... -: :.iiE--T ---fiS if -ff. -:-.tt';; -- i.E .-EE.E if i:: iL iE:EE:iE::
- E-.i.:: -....: .:. i.: i....i. i: ..---:::::::: ::::: i -" ':.':: : :E-: tiEd E ;-, i:: Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer Jeffrey D. Cross Senior Vice President, General Counsel and : Assistant Secretary.
Joseph Hamrock Senior Vice President: -General Services :: Dale E. Heydlauff Senior Vice President -Governmental and Environmental Affairs Michelle S. Kalnas Senior Vice President -Supiply Chain, 'Richard E. Munczinski Senior Vice Preside'nt -Corporate Planning .:-and Budgeting: Armando A. Pe a (l}Senior Vice President -Finance and Treasurer Michael W.: Rencheck .-Senior Vice President -Technical Services:: m William L Sigmon, Jr.:-: Senior Vice President -:: 0 Fossil and Hyro H.Generation -Scott N. Smith -Senior Vice President .-. : W and Chief Risk Officer:0 3 03-........ .-(-,....::.....L- -- i i t i O* iE i,, E iSE, i .:: i -:_:~Henry W. Fayne Vice President Armando A. Pe a.Treasurer Susan Tomasky Vice President, Secnr and Chief Financial Joseph M. Buonaii ,.-1 ,, , ...E Controller and..Chief Accounting 0 I i.','I I % -.I .I"" " n-, .;_ -.1 : fil, .,-,R 2-71N7-30, _,_-:,_1_Annual Meeting -The 96th annual meeting of shareholders of American Electric Power Company will be held at 9:30 a-m.Wednesday, April 23, 2003, at The Ohio State University's Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio. Admission is by ticket only. To obtain a ticket, please note the instructions in the Notice of Annual Meeting mailed to shareholders or call the Company. If you hold your shares through a broker, please bring proof of share ownership as of the record date.Shareholder Inquiries -If you have questions about your account, contact the Company's transfer agent, listed below. You should have your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the shareholder's approval or appropriate documents. Transfer Agent & Registrar EquiServe Trust Company, N.A.(formerly First Chicago Trust Company of New York)P.O. Box 43069 Providence, RI 02940-3069 Telephone Response Group: 1-800-328-6955 Internet address: www.equiserve.com Hearing Impaired #: TDD: 1-800-952-9245 Internet Access to Your Account -If you are a registered shareholder, you can access your account information through the Internet at www.equiserve.com. Information about obtaining a password is available toll-free at 1-877-843-9327. Replacement of Dividend Checks -If you do not receive your dividend check within five business days after the dividend'pay-ment date, or if your check is lost, destroyed or stolen, you should notify the transfer agent for a replacement. Lost or Stolen Stock Certificates -If your stock certificate is lost, destroyed or stolen, you should notify the transfer agent immediately so a 'stop transfer' order can be placed on the missing certificate. The transfer agent then will send you the required documents to obtain a replacement certificate. Address Changes -It is important that we have your current address on file so that you do nor become a lost shareholder. Please contact the transfer agent for address changes fbr both record and dividend mailing addresses. We also can provide automatic seasonal address changes.Stock Transfer -Please contact the transfer agent if you have questions regarding the transfer of stock and related legal requirements,. -Dividend Rei'nvestment and Direct Stock Purchase Plan -A Dividend Reinvestment and Direct Stock Purchase Plan is avail-able to all investors. It is an' economical and convenient method of purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent... i Direct Deposit of Dividends -The Company does offer electronic deposit of your dividends. Contact the transfer agent for details.Stock Held in Brokerage Account ('Street Name') -When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker's name or 'street name.' AEP does not know the identity of idivdual shareholders who hold their shares in this manner, we simply know that a broker holds a certain number of shares which'may be for any number of customers. If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any questions you may have about your account should be directed to your broker.How to Consolidate Accounts -If you want to consolidate your separate accounts into one account, you should contact the transfer agent to obtain the necessary instructions. When accounts are consolidated, it' may be necessary to reissue the stock certificates.
- C X .,. .. .-....- ' --A. ..f
- .- .- ..... ... E i !
- ; A :. : .How to Eliminate Duplicate Mailings -If you want to maintain more than one account but eliminate additional mailings of annual reports, you may do so by contacting the transfer agent, indicating the names you wish to keep on the mailing list for annual reports and the names you wish to delete. This will affect only these mailings; dividend checks and proxy materials will continue to be sent to each accountI:
IdE i-Stock Trading -The Company's common stock is traded princi-pally on the New York Stock Exchange under the ticker symbol.AER AEP stock has been traded on the NYSE for 54 years.Taxes on Dividends -The Company paid $2.40 in cash dividends in 2002, all of which' are taxable for federal income tax purposes.AEP has paid consecutive quarterly dividends since 1910.Shareholder Direct -An array of timely recorded messages.about AEP, including dividend and earnings information and recent news releases, is available from AEP Shareholder Direct at 1-800-551-lAEP (1237) anytime day or night. Hard copies of information can be obtained via fax or mail. Requests for annual reports, 10-K's, 10-Q's, Proxy Statements and Summary Annual I Reports should be made through Shareholder Direct.Financial Community Inquiries -Institutional investors or secunities analysts who have questions about the Company;should direct inquiries to Bette Jo Rozsa, 614-716-2840, bjrozsa@aep.com, orJulie Sloar, 614-716-2885, jsloat@aep.com; individual shareholders should contact Kathleen Kozero, : 614-716-2819, klkozero@aep.com, or April Dawson, 614-716-2591 addawson aep.com.Internet Home Page -Information about AEP, including financial documents, SEC filings, news releases and customer service information, is available on the Company's home page,:, on the Internet at www..aep.coml .Annual Report and Proxy Materials -You can receivei: future annual reports, proxy statements and proxies electronically rather than by mail; if you are'a registered holder, log on to wvww.econsent.comlaep.- If you hold your shares in street name, contact your broker.-7IEI:Ii; Cd, M E: E.Li) WA MT NO MN i ME OR I0 C.. : F:ti'S .C) N- W I-l, So WY M!VT NH NY I MA CT RI NJ[A NE NV UT MD CA co NM KS MO DE ,, , -OKDr TN NC AZ AR LA SC MS AL GA-AEP service area-; Transmission lines FL More than 42,000 megawatts of electric generating capacity, including the largest generation fleet in the U.S.-38,000 circuit miles of transmission lines 186,000 miles of distribution lines:.128 billion cubic feet of gas storage 6,400 miles of natural gas pipeline 7,000 rail cars 1,800.barges and 37 tug boats .Annual coal production capability of 10 million tons American Electric Power owns and operates more than;'42,000 megawatts of generating capacity in the United.States and select international markets and is the largest electricity generator in the U.S. AEP is also one of the largest electric utilities in the United States, with almost 5 million customrers linked to AEP's electricity transmission and distribution grid. Those customers are located in 11 states -Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio Oklahoma, Tennessee, Texas, Virginia and West Virginia. The company's distribution service area:*6covers 197,500 square miles., Outside the United States, AEP holds interests in the United Kingdom, Australia, Brazil, China, Mexico and the Pacific Regions bs i C Ohio..AEP is based in Columbus, Ohio. 4 f 0;>z -z e
2002 Annual Reports American Electric Power Company, Inc.AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Audited Financial Statements and Management s Discussion and Analysis AMERICAN ELECTRIC POWER AEPh.rnfefica:s EnewTy Partner' Contents Page Glossary of Terms i Forward Looking Information iv AEP Common Stock and Dividend Information v American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Operations A-9 Consolidated Balance Sheets A-10 Consolidated Statements of Cash Flows A-12 Consolidated Statements of Common Shareholders Equity and Comprehensive Income A-13 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-14 Schedule of Consolidated Long-term Debt of Subsidiaries A-15 Index to Combined Notes to Consolidated Financial Statements A-1 6 Independent Auditors' Report A-17 Management's Responsibility A-18 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Combined Notes to Financial Statements B-8 Independent Auditors' Report B-9 AEP Texas Central Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income C-5 Consolidated Statements of Retained Earnings C-6 Consolidated Balance Sheets C-7 Consolidated Statements of Cash Flows C-9 Consolidated Statements of Capitalization C-1 0 Schedule of Long-term Debt C-1I Index to Combined Notes to Consolidated Financial Statements C-13 Independent Auditors' Report C-1 4 AEP Texas North Company Selected Financial Data D-A Management's Narrative Analysis of Results of Operations D-2 Statements of Operations and Statements of Comprehensive Income D-4 Statements of Retained Earnings D-5 Balance Sheets D-6 Statements of Cash Flows D-8 Statements of Capitalization D-9 Schedule of Long-term Debt D-1 0 Index to Combined Notes to Financial Statements D-1 1 Independent Auditors' Report D-1 2 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Discussion and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income E-5 Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-1 0 Schedule of Long-term Debt E-1 I Index to Combined Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-1 3 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Narrative Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income F-4 Consolidated Statements of Retained Earnings F-5 Consolidated Balance Sheets F-6 Consolidated Statements of Cash Flows F-8 Consolidated Statements of Capitalization F-9 Schedule of Long-term Debt F-1 0 Index to Combined Notes to Consolidated Financial Statements F-11 Independent Auditors' Report F-1 2 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data G-1 Management's Discussion and Analysis of Results of Operations G-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income G-5 Consolidated Statements of Retained Earnings G-6 Consolidated Balance Sheets G-7 Consolidated Statements of Cash Flows G-9 Consolidated Statements of Capitalization G-10 Schedule of Long-term Debt G-1I Index to Combined Notes to Consolidated Financial Statements G-12 Independent Auditors' Report G-13 Kentucky Power Company Selected Financial Data H-1 Management's Narrative Analysis of Results of Operations H-2 Statements of Income, Statements of Comprehensive Income and Statements of Retained Earnings H4 Balance Sheets H-5 Statements of Cash Flows H-7 Statements of Capitalization H-8 Schedule of Long-term Debt H-9 Index to Combined Notes to Financial Statements H-10 Independent Auditors' Report H-11 --Ohio Power Company Selected Financial Data 1-1 Management's Discussion and Analysis of Results of Operations 1-2 Statements of Income and Statements of Comprehensive Income 1-5 Statements of Retained Earnings 1-6 Balance Sheets 1-7 Statements of Cash Flows 1-9 Statements of Capitalization 1-10 Schedule of Long-term Debt 1-11 Index to Combined Notes to Financial Statements 1-12 Independent Auditors' Report 1-13 Public Service Company of Oklahoma and Subsidiary Selected Consolidated Financial Data J-1 Management's Narrative Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income J-4 Consolidated Statements of Retained Earnings J-5 Consolidated Balance Sheets J-6 Consolidated Statements of Cash Flows J-8 Consolidated Statements of Capitalization J-9 Schedule of Long-term Debt J-10 Index to Combined Notes to Consolidated Financial Statements J-1 1 Independent Auditors' Report J-1 2 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data K-1 Management's Discussion and Analysis of Results of Operations K-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income K-4 Consolidated Statements of Retained Earnings K-5 Consolidated Balance Sheets K-6 Consolidated Statements of Cash Flows K-8 Consolidated Statements of Capitalization K-9 Schedule of Long-term Debt K-1 0 Index to Combined Notes to Consolidated Financial Statements K-1 I Independent Auditors' Report K-1 2 Combined Notes to Financial Statements L-1 Registrants Combined Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters M-1 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below: Term Meaning 2004 True-up Proceeding ........ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs.AEGCo .. ................... AEP Generating Company, an electric utility subsidiary of AEP.AEP .................. American Electric Power Company, Inc.AEP Consolidated .................... AEP and its majority owned consolidated subsidiaries. AEP Credit .................. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and non-affiliated domestic electric utility companies. AEP East companies ............... APCo, CSPCo, I&M, KPCo and OPCo.AEPR .................. AEP Resources, Inc.AEP System or the System ....... The American Electric Power System, an integrated electric utility system, owned and operated by AEP s electric utility subsidiaries. AEPSC .................... American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. AEP Power Pool .................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. AEP West companies ............... PSO, SWEPCo, TCC and TNC.AFUDC .................... Allowance forfunds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant.Alliance RTO .. .................. Alliance Regional Transmission Organization, an ISO formed byAEP and four unaffiliated utilities (the FERC overturned earlier approvals of this RTO in December 2001).Amos Plant ................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.APCo ..................... Appalachian Power Company, an AEP electric utility subsidiary. Arkansas Commission ............. Arkansas Public Service Commission. Buckeye .................. Buckeye Power, Inc., an unaffiliated corporation. CLECO .................. Central Louisiana Electric Company, Inc., an unaffiliated corporation. COLI .................. Corporate owned life insurance program.Cook Plant .................. The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.CPL .................... Central Power and Light Company [legal name changed to AEP Texas Central Company (TCC) effective December 2002]. See TCC.CSPCo .................... Columbus Southern Power Company, an AEP electric utility subsidiary. CSW ...... ............ Central and South West Corporation, a subsidiary of AEP (Effective January 21,2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).CSW Energy ................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.CSW International .................... CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States.D.C. Circuit Court .................... The United States Court of Appeals for the District of Columbia Circuit.DHMV ................... Dolet Hills Mining Venture.DOE .................. United States Department of Energy.ECOM ................... Excess Cost Over Market.ENEC .................... Expanded Net Energy Costs.EITF .................... The Financial Accounting Standards Board s Emerging Issues Task Force.ERCOT .................. The Electric Reliability Council of Texas.EWGs .................. Exempt Wholesale Generators. FASB .................. Financial Accounting Standards Board.Federal EPA .................. United States Environmental Protection Agency.i FERC ................ Federal Energy Regulatory Commission. FMB ..... ........... First Mortgage Bond.FUCOs ...... .......... Foreign Utility Companies. GAAP ..... ........... Generally Accepted Accounting Principles. I&M ................ Indiana Michigan Power Company, an AEP electric utility subsidiary. ICR ................ Interchange Cost Reconstruction. IPC .... ............ Installment Purchase Contract.IRS .... ............ Internal Revenue Service.IURC ................ Indiana Utility Regulatory Commission. ISO .... ............ Independent System Operator.Joint Stipulation .. ................ Joint Stipulation and Agreement for Settlement of APCo s WV rate proceeding. KPCo ................ Kentucky Power Company, an AEP electric utility subsidiary. KPSC ................ Kentucky Public Service Commission. KWH .................. Kilowatthour. LIG ................ Louisiana Intrastate Gas.Michigan Legislation ................ The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.MISO .................. Midwest Independent System Operator (an independent operator of transmission assets in the Midwest).MLR ................ Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.Money Pool ........ ........ AEP System s Money Pool.MPSC ................ Michigan Public Service Commission. MTM ..... ........... Mark-to-Market. MTN ..... ........... Medium Term Notes.MW ................ Megawatt.MWH ..... ........... Megawatthour. NEIL ..... ........... Nuclear Electric Insurance Limited.NOx ................ Nitrogen oxide.NOx Rule ................ A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate.NP .................. Notes Payable.NRC ................ Nuclear Regulatory Commission. Ohio Act ................ The Ohio Electric Restructuring Act of 1999.Ohio EPA ................ Ohio Environmental Protection Agency.OPCo ................ Ohio Power Company, an AEP electric utility subsidiary. OVEC ................ Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.PCBs ................ Polychlorinated Biphenyls. PJM .................. Pennsylvania New Jersey Maryland regional transmission organization. PRP ................ Potentially Responsible Party.PSO ................ Public Service Company of Oklahoma, an AEP electric utility subsidiary. PUCO ................ The Public Utilities Commission of Ohio.PUCT .................. The Public Utility Commission of Texas.PUHCA ................ Public Utility Holding Company Act of 1935, as amended.PURPA ................ The Public Utility Regulatory Policies Act of 1978.RCRA .... ............ Resource Conservation and Recovery Act of 1976, as amended.Registrant Subsidiaries ............. AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.REP ................ Retail Electric Provider.Rockport Plant ................ A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and l&M.RTO ................ Regional Transmission Organization. ii SEC ............. Securities and Exchange Commission. SFAS .... ......... Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.SFAS 71 ............... Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. SFAS 101 ............... Statement of Financial Accounting Standards No. 101, Accounting forthe Discontinuance of Application of Statement 71.SFAS 133 ............. Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. SNF ............. Spent Nuclear Fuel.SPP ............... Southwest Power Pool.STP ............... South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an AEP electric utility subsidiary. STPNOC ..... ........ STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including TCC.Superfund ............. The Comprehensive Environmental, Response, Compensation and Liability Act.SWEPCo ............... Southwestern Electric Power Company, an AEP electric utility subsidiary. TCC ............. AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central Power and Light Company (CPL)].Texas Appeals Court ............. The Third District of Texas Court of Appeals.Texas Legislation .. ............. Legislation enacted in 1999 to restructure the electric utility industry in Texas.TNC ............. AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas Utilities Company (WTU)].Travis District Court ............. State District Court of Travis County, Texas.TVA ............... Tennessee Valley Authority. U. ............. The United Kingdom.UN ............. Unsecured Note.VaR ............... Value at Risk, a method to quantify risk exposure.Virginia SCC ............. Virginia State Corporation Commission. WV ............... West Virginia.WVPSC ............... Public Service Commission of West Virginia.WPCo ............. Wheeling Power Company, an AEP electric distribution subsidiary. WTU ............. West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective December 2002]. See TNC.Yorkshire ............... Yorkshire Electricity Group pic, a U.K. regional electricity company owned jointly by AEP and New Century Energies until April 2001.Zimmer Plant ............. William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary. iii FORWARD LOOKING INFORMATION These reports made byAEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21 E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:* Electric load and customer growth.* Abnormal weather conditions. .Available sources and costs of fuels.* Availability of generating capacity.* The speed and degree to which competition is introduced to our service territories.
- The ability to recover stranded costs in connection with possible/proposed deregulation.
- New legislation and government regulation.
- Oversight and/or investigation of the energy sector or its participants.
- The ability of AEP to successfully control its costs.* The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile.* International and country-specific developments affecting AEP's foreign investments including the disposition of any current foreign investments and potential additional foreign investments.
.The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.* Inflationary trends.* Electricity and gas market prices.* Interest rates.* Liquidity in the banking, capital and wholesale power markets..Actions of rating agencies.* Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. .Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.iv AEP Common Stock and Dividend Information The quarterly high and low sales prices and the quarter-end closing price for AEP common stock and the cash dividends paid per share are shown in the following table: Quarter-end Quarter Ended High Low Closing Price Dividend March 2002 $47.08 $39.70 $46.09 $0.60 June 2002 48.80 39.00 40.02 0.60 September 2002 40.37 22.74 28.51 0.60 December2002 30.55 15.10 27.33 0.60 March 2001 $48.10 $39.25 $47.00 $0.60 June 2001 51.20 45.10 46.17 0.60 September 2001 48.90 41.50 43.23 0.60 December 2001 46.95 39.70 43.53 0.60 AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003 management recommended thatthe Company reduce dividends by approximately 40% after payment of the March 2003 dividend which was approved by the Company s Board of Directors at the current level of $0.60 per share.v AMERICAN ELECTRIC POWER COMPANY, INC.AND SUBSIDIARY COMPANIES AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES selected consolidated Financial Data Year Ended December 31, 2002 2001 2000 1999 1998 OPERATIONS STATEMENTS DATA (in millions): Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080 operating Income 1,263 2,182 1,774 2,061 2,046 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 21 917 180 869 859 Discontinued operations Income (Loss) (190) 86 122 117 116 Extraordinary Losses -(50) (35) (14) _Cumulative Effect of Accounting change Gain (Loss) (350) 18 ---Net Income (Loss) (519) 971 267 972 975 December 31. 2002 2001 2000 1999 1998 BALANCE SHEET DATA (in millions): Property, Plant and Equipment $37,857 $37,414 $34,895 $33,930 $32,400 Accumulated Depreciation and Amortization 16.173 15.310 14.899 14.266 13.374 Net Property, Plant and Equipment $22,104 $19,996 S1 5664 Total Assets $34,741 $39,297 $46,633 $35,296 $33,418 Common shareholders' Equity 7,064 8,229 8,054 8,673 8,452 Cumulative Preferred Stocks of Subsidiaries* 145 156 161 182 350 Trust Preferred securities 321 321 334 335 335 Long-term Debt* 10,496 9,505 8,980 9,471 9,215 Obligations under capital Leases* 228 451 614 610 539 Year Ended December 31. 2002 2001 2000 1999 1998 COMMON STOCK DATA: Earnings per Common share: Before Discontinued operations, Extraordinary Items and cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70 Discontinued Operations (0.57) 0.26 0.38 0.36 0.36 Extraordinary Losses -(0.16) (0.11) (0.04) -cumulative Effect of Accounting change (1.06) 0.06 ---Earnings (Loss) Per share (1.5) $3.1 $0-83 $ 3.03 $_3.0 Average Number of shares Outstanding (in millions) 332 322 322 321 318 Market Price Range: High $ 48.80 $51.20 $48-15/16 $48-3/16 $53-5/16 Low 15.10 39.25 25-15/16 30-9/16 42-1/16 Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16 cash Dividends on Common** $ 2.40 $2.40 S2.40 $2.40 $2.40 Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%Book value per share $20.85 $25.54 $25.01 $26.96 $26.46*Including portion due within one year. Long-term Debt includes Equity unit senior Notes.**Based on AEP historical dividend rate. See "Common stock and Dividend Information (on page v) regarding the potential reduction of future dividends. A-1 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Managements Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S. We provide generation, transmission and distribution service to almost five million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. We have a vast portfolio of assets including:
- 38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in our market areas.4,000 megawatts of generating capacity in the U.K., a countrywhich is currently experiencing excess generation capacity* 38,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S.* 186,000 miles of distribution lines that support delivery of electricity to our customers premises a Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity)* 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of gas storage facilities Business Strategy We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets. We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business.Through our utility operations focus, we intend to be the energy and low cost generation provider of choice. We have ample generation to meet our customers needs.We have a cost advantage resulting from AEP s long tradition of designing, building and operating efficient power plants and delivery networks.
Our customers continue to show top quartile level of satisfaction. We provide safe and reliable sources of energy.Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors. We are addressing many challenges in our unregulated business. We have already substantially reduced our trading activities. We have written down the value of several investments to reflect deterioration in market conditions. We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy. We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling. Transition rules for Michigan and Virginia do not require legal separation. Deregulation is no longer an expectation in the foreseeable future in the other states where we operate.Our strategy for the core business of utility operations is to:.Maintain moderate but steady earnings growth* Maximize value of transmission assets and protect our revenue stream in an RTO membership environment
- Continue process improvement to maintain distribution service quality while, at the same time, further enhancing financial performance
- Optimize generation assets through increased availability and sale of A-2 excess capacity Manage the regulatory process to maximize retention of earnings improvement while providing fair and reasonable rates to our customers We remain very focused on credit quality and liquidity as discussed in greater detail later in this report.We are committed to continually evaluating the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and sustainable shareholder value. Any investment dispositions could affect future results of operations, cash flows and possibly financial condition.
2002 Overview 2002 was a year of rapid and dramatic change for the energy industry, including AEP, as the wholesale energy market quickly shrank and many of its participants exited or significantly limited future trading activity.Investors lost confidence in corporate America and the economy stalled. Investors demand for stability, predictable cash flows, earnings, and financial strength have replaced their demand for rapid growth.Our wholesale business did not perform well.We had significant losses in options trading in the first half of the year and new investments performed well below our expectations. We focused on financial strength by:* Issuing approximately $1 billion in common stock and equity units.Retiring debt of approximately $3 billion through the sale of two foreign retail utility companies in the U.K.(SEEBOARD) and Australia (CitiPower)
- Establishing a cash liquidity reserve of$1 billion at year-end See Financing Activity in Managements Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters in section M for an overview of all changes to capital structure.
We also focused on:* Implementing an enterprise-wide risk management system* Completing a cost reduction initiative which we expect to result in sustainable net annual savings of more than $200 million beginning in 2003* Eliminating or reducing future capital requirements associated with non-core assets We have redirected our business strategy by:* Scaling back trading activities to focus principally on supporting our core assets* Selling our Texas retail business.Proposing the sale of a significant portion of the Texas unregulated generation assets Outlook for 2003 We remain focused on the fundamental earnings power of our utility operations, and we are committed to strengthening our balance sheet. Our strategy for achieving these goals is well planned:* First, we will continue to identify opportunities to reduce our operations and maintenance expense.* Second, we will find opportunities to reduce capital expenditures.
- Third, management recommended a 40% reduction in the common stock dividend beginning in the second quarter to a quarterly rate of $0.35 per share. This will result in annual cash savings of approximately
$340 million and should improve our retained earnings as well as create free cash flow to improve liquidity and pay-down outstanding debt.* Fourth, we plan to evaluate and, where appropriate, dispose of non-core assets. Proceeds from these sales will be used to reduce debt..Fifth, we will continue to evaluate the potential for issuing additional equity to further strengthen our balance sheet and maintain credit quality.We remain committed to being a low cost provider of electricity, to serving our A-3 customers with excellence and to providing an attractive return to investors. We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets.Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management s Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters. We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors. Results of Operations In 2002, AEP s principal operating business segments and their major activities were:* Wholesale: o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity trans-mission o Domestic electricity distri-bution* Other Investments o Energy Services Net Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001. The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. In 2002, the Company s Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3).Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP s wholesale marketing business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. The effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron s bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.Our wholesale business has been affected by a slowing economy. Wholesale energy margins and energy use by industrial customers declined in 2002 and 2001.Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO.Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues in 2002 and 2001.Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001.A-4 Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be more volatile. See 'Market Risks section for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. Revenues Increase AEP s total revenues increased 14% in 2002 and 15% in 2001. The following table shows the components of revenues: For The Year Ended December 31 2002 2001 2000 (in millions)WHOLESALE: Residential $ 3,713 commercial 2,156 Industrial 1,903 other Retail customers 385 Electricity Marketing (net) 2,227 unrealized MTM Income-Electric 136 other 1,397 Less: Transmission and Distribution Revenues Assigned to Energy Delivery* (3.551)wholesale Electric 8.366 S 3,553 2,328 2,388 S 3,511 2,249 2,444 419 414 802 1,073 210 38 632 837 has had a major effect on the volume of wholesale power marketing especially in the short-term market.The increase in 2002 in wholesale revenues resulted from a 27% increase in trading volume associated with Wholesale Electricity which was offset by a continuing decrease in gross margins which began in the fourth quarter of 2001, and an increase in residential sales as a result of favorable weather conditions in the third quarter 2002.In addition OtherWholesale electric revenues increased due to the mid-year 2001 acquisition of barging and coal mining operations as well as the recognition of revenues for generation projects completed for third parties. The increase in 2002 Wholesale Gas revenues resulted from a full year of HPL operations compared to a partial year from our acquisition date in July 2001, offset by a decrease in the results from financial trading and MTM unrealized losses.Other Investments revenue decreased in 2002 due to the elimination of factoring of accounts receivable of an unaffiliated utility.Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 1).Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in 2001. This decrease was due to the economic slow down which began in late 2001. Sales to residential customers rose 5%due to weather related demand in 2002. The economic slow down reduced demand and wholesale prices especially in the latter part of 2001.i (3.356) (3.174)6,97 7,392 Gas Marketing (net) 3,021 2,274 unrealized MTM Income (Loss)-Gas (399) 47 wholesale Gas 2.622 2.321 TOTAL WHOLESALE 10.988 9.297 310 132 442 7,834 DOMESTIC ELECTRICITY DELIVERY: Transmi ssi on Distribution TOTAL DOMESTIC ELECTRICITY DELIVERY OTHER INVESTMENTS 922 1,029 1,009 2.629 2,327 2.165 3.551 3,356 3,174 16 114 105 TOTAL REVENUES S14,5m 11.77 ,*Certain revenues in the wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.The level of electricity transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC s introduction of a greater degree of competition into the wholesale energy market A-5 I Ooeratina ExDenses Increase Changes in the components of operating expenses were as follows: Inc Fr Amour Fuel and Purchased Energy: Electricity $ 959 Gas 404 Maintenance and other operation 303 Non-recoverable Merger Costs (11)Asset Impairments 867 Depreciation and Amortization 134 Taxes other Than Income Taxes 51 Total:rease (Decrease) tom Previous Year 2002 200.(in millions)it % Amount %43.7 S(1,275)(36.7) 14.7 2,339 570.5 8.2 i (52.4)N.M.228 6.5 (182) (89.7)CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected, merger costs declined in 2001 and 2002 after the merger was consummated. In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling $1.4 billion (consisting of approximately, $866.6 million related to asset impairments, $321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included: 2002 Pre-Tax Estimated Loss (in millions)10.8 152 13.9 7.6 (16) (2.3)25.6 51.246 13.3 The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001. The return to service of the Cook Plants two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation. The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001.The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full years expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001.Maintenance and Other Operation expense rose in 2001 mainly as a result of additional traders incentive compensation and accruals for severance costs related to corporate restructuring. With the consummation of the merger with Asset Impairments Held for sale Asset Impairments Held and used Investment value Losses S 483.1 651.4 291.9 Total Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations. The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service.Depreciation and Amortization expense increased in 2001 primarily as a result of the A-6 commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and WestVirginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in Property, Plant and Equipment. Taxes OtherThan IncomeTaxes increased in 2002 due to a full year of state excise taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in Texas partly offset by the effect of Texas one-time 2001 assessments and decreased gross Texas receipts taxes due to deregulation. Interest. Preferred Stock Dividends, Minority Interest The decrease in Interest in 2002 was primarily due to a reduction in short-term interest rates and lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates offset in part by an increased amount of long-term debt outstanding. Interest expense decreased 15% in 2001 due to the effect of interest paid to the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.Minority Interest in Finance Subsidiary increased substantially in 2002 because the distributions to minority interest were in effect for the entire year. In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest. The minority interest was only in effect during the last four months of 2001.Other Income/Other Expenses This increase was primarily caused by an increase in equity earnings due to acquisitions of $63 million and a $73 million gain from the sale of a generating plant (see Note 1). Other Expenses increased by $110 million or 143%in 2001 due to costs to exit air transportation, fiber optic and Datapult businesses (see Note 1).Income Taxes The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book income offset by the tax effects of the sale of foreign operations. Although pre-tax book income increased considerably in 2001, Income Taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000.Extraordinary Losses and Cumulative Effect The loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change on January 1, 2002.In 2001 we recorded an extraordinary loss of$48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after-tax extraordinary loss of $35 million.New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark-to-market certain fuel supply contracts that qualify as financial derivatives. The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a Cumulative Effect of Accounting Change.Other Income increased by $110 million or 33% in 2002 due to the sale of AEP S retail electric providers in Texas and due to non-operational revenue (see Note 1). Other Expenses increased $134 million or 72% in 2002 due to non-operational expenses (see Note 1).Other Income increased $240 million in 2001.A-7 mI Discontinued Operations The operations shown below were discontinued or held for sale in 2002 (See Note 12). Results of operations including impairment losses, net of tax, of these businesses have been reclassified: Company 2002 2001 2000 (in millions)SEEBOARD 5 96 S 88 5 99 CitiPower (123) (6) 17 Pushan (7) 4 7 Eastex (156) -(1)90) 5 86 S12 Reclassification Balance sheet amounts have been restated to reflect our change in accounting policy regarding certain assets and liabilities related to forward physical and financial transactions (see "Reclassification discussion Note 1.)Based upon AEP s legal rights of offset, physical and financial contracts were netted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not netted in 1998 amounts as the impact is not material.A-8 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Operations (in millions -except per share amounts)Year Ended December 31.2002 2001 2000 REVENUES: wholesale Electricity S 8,366 S 6,976 $ 7,392 wholesale Gas 2,622 2,321 442 Domestic Electricity Delivery 3,551 3,356 3,174 other Investment 16 114 105 TOTAL REVENUES 14,555 12.767 11.113 EXPENSES: Fuel and Purchased Energy: Electricity 3,154 2,195 3,470 Gas 3.153 2,749 410 TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880 Maintenance and other operation 4,013 3,710 3,482 Non-recoverable Merger Costs 10 21 203 Asset Impairments 867 --Depreciation and Amortization 1,377 1,243 1,091 Taxes other Than Income Taxes 718 667 683 TOTAL EXPENSES 13.292 10,585 9,339 OPERATING INCOME 1,263 2,182 1,774 OTHER INCOME 445 335 95 LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 --LESS: OTHER EXPENSES 321 187 77 LESS: INTEREST 785 844 999 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 11 10 11 MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -INCOME BEFORE INCOME TAXES 235 1,463 782 INCOME TAXES 214 546 602 INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT 21 917 180 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122 EXTRAORDINARY LOSSES (NET OF TAX): DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION -(48) (35)LOSS ON REACQUIRED DEBT -(2) -CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -NET INCOME (LOSS) S 51) $ 971 $ 267 AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322 EARNINGS-(LOSS) PER SHARE: Income Before Discontinued operations, Extraordinary Items and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56 Discontinued Operations (0.57) 0.26 0.38 Extraordinary Losses -(0.16) (0.11)Cumulative Effect of Accounting change (1.06) 0.06 Earnings (Loss) Per share (Basic and Diluted) I$(1.5) L3.01 $ 0.83 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 J24 See Notes to Consolidated Financial Statements beginning on page L-1.A-9 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (in millions -except share data)December 31.2002 2001 ASSETS CURRENT ASSETS: Cash and cash Equivalents $ 1,213 $ 224 Accounts Receivable: customers 466 343 Miscellaneous 1,394 1,365 Allowance for uncollectible Accounts C119) (69)Fuel, Materials and Supplies 1,166 1,037 Energy Trading and Derivative Contracts 1,046 2,125 other 935 639 TOTAL CURRENT ASSETS 6,101 5,664 PROPERTY, PLANT AND EQUIPMENT: Electric: Production 17,031 17,054 Transmission 5,882 5,764 Distribution 9,573 9,309 Other (including gas and coal mining assets and nuclear fuel) 3,965 4,272 Construction work in Progress 1,406 1,015 Total Property, Plant and Equipment 37,857 37,414 Accumulated Depreciation and Amortization 16,173 15,310 NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104 REGULATORY ASSETS 2,688 3,162 SECURITIZED TRANSITION ASSETS 735 -INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633 ASSETS HELD FOR SALE 247 721 ASSETS OF DISCONTINUED OPERATIONS -3,954 GOODWILL 396 392 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795 OTHER ASSETS 1.783 1,872 TOTAL ASSETS $34,741 See Notes to Consolidated Financia1 Statements beginning on page L-1.A-10 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31, 2002 2001 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,042 S 1,914 short-term Debt 3,164 4,011 Long-term Debt Due within one Year* 1,633 1,095 Energy Trading and Derivative Contracts 1,147 1,877 other 1.804 1.924 TOTAL CURRENT LIABILITIES 9.790 10,821 LONG-TERM DEBT* 8.487V 8.410 EQUITY UNIT SENIOR NOTES 376 -LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603 DEFERRED INCOME TAXES 3.916 4.500 DEFERRED INVESTMENT TAX CREDITS 455 491 DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819 DEFERRED GAIN ON SALE AND LEASEBACK -ROCKPORT PLANT UNIT 2 185 194 OTHER NONCURRENT LIABILITIES 1.903 1.334 LIABILITIES HELD FOR SALE 91 87 LIABILITIES OF DISCONTINUED OPERATIONS -2.582 COMMITMENTS AND CONTINGENCIES (Note 9)CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH 321 321 SUBSIDIARIES MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 145 156 COMMON SHAREHOLDERS' EQUITY: Common Stock-Par value $6.50: 2002 2001 shares Authorized. .600,000,000 600,000,000 shares Issued. ...347,835,212 331,234,997 (8,999,992 shares were held in treasury at December 31, 2002 and 2001) 2,261 2,153 Paid-in Capital 3,413 2,906 Accumulated other Comprehensive Income (Loss) (609) (126)Retained Earnings 1,999 3,296 TOTAL COMMON SHAREHOLDERS' EQUITY 7.064 8,229 TOTAL LIABILITIES AND SHAREHOLDERS EQUITY $ $39297*See Accompanying schedules. See Notes to Consolidated Financial Statements beginning on page L-1.A-11 I AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated statements of cash Flows (in millions)Year Ended December 31.2002 2001 2000 OPERATING ACTIVITIES: Net Income (Loss) $ (519) S 971 $ 267 Plus: Discontinued operations 540 (86) (122)Net income from Continuing operations 21 885 145 Adjustments for Noncash Items: Asset Impairments, Investment value and other Impairments 1,188 --Depreciation and Amortization 1,403 1,277 1,152 Deferred Investment Tax Credits (31) (29) (36)Deferred Income Taxes (66) 157 (190)Amortization of operating Expenses and Carrying charges 40 40 48 cumulative Effect of Accounting Change (18) -Equity Earnings of Yorkshire Electricity Group plc -(44)Extraordinary Loss 50 35 Deferred costs under Fuel clause Mechanisms (31) 340 (449)Mark-to-Market of Energy Trading Contracts 263 (257) (170)Miscellaneous Accrued Expenses 30 (384) 217 changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (152) 1,766 (1,530)Fuel, Materials and Supplies (127) (78) 149 Accrued Revenues (283) 35 (71)Accounts Payable 52 (478) 1,292 Taxes Accrued (216) (147) 171 Payment of Disputed Tax and Interest Related to COLI --319 change in other Assets (177) (239) (283)change in other Liabilities (237) (161) 386 Net cash Flows From Operating Activities 1,677 2,759 1.141 INVESTING ACTIVITIES: Construction Expenditures (1,722) (1,654) (1,468)Purchase of Gas Pipe Line -(727) -Purchase of U.K. Generation -(943) -Purchase of coal Company -(101) -Purchase of Barging Operations -(266) -Purchase of wind Generation -(175) -Proceeds from Sale of Retail Electric Providers 146 --Proceeds from sale of Foreign Investments 1,117 383 -Proceeds from Sale of U.S. Generation -265 -other 37 (42) (18)Net Cash FlowS used For Investing Activities (422) (3.260) (1.486)FINANCING ACTIVITIES: Issuance of Common stock 656 11 14 Issuance of Minority Interest -744 -Issuance of Long-term Debt 2,893 2,863 878 Issuance of Equity unit Senior Notes 334 -Retirement of Cumulative Preferred stock (10) (5) (21)Retirement of Long-term Debt (2,514) (1,570) (1,303)change in short-term Debt (net) (829) (790) 1,328 Dividends Paid on Common stock (793) (773) (805)Dividends on Minority Interest in subsidiary -(5) -Net Cash Flows From (used for) Financing Activities (263) 475 91 Effect of Exchange Rate Changes on Cash (3) (1) 30 Net Increase (Decrease) in cash and cash Equivalents 989 (27) (224)cash and cash Equivalents from Continuing operations Beginning of Period 224 251 475 Cash and cash Equivalents from Continuing Operations -End of Period $L213 L 224 S 251.Net Increase (Decrease) in Cash and cash Equivalents from Discontinued operations $ (100) $ 17 $ (17)Cash and cash Equivalents from Discontinued operations Beginning of Period 108 91 108 Cash and Cash Equivalents from Discontinued operations End of Period $ 8A08 $ 91 See Notes to consolidated Financial Statements beginning on page L-1.A-12 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equitv and Comprehensive Income (in millions)DECEMBER 31, 1999 Issuances cash Dividends Declared Other comprehensive Income: Other Comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment Reclassification Adjustment For LOSS Included in Net Income Net Income Total Comprehensive Income DECEMBER 31, 2000 Issuances cash Dividends Declared other comprehensive Income: Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability Net Income Total Comprehensive Income DECEMBER 31, 2001 Issuances cash Dividends Declared Other Com prehensive Income: Other comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability unrealized Loss on securities Available For Sale Net Income (Loss)Total comprehensive Income DECEMBER 31, 2002 Common stock shares Amount 331 $2,149-3 331 331 17$2, 152 1$2,153 108 Paid-In Capi tal$2,898 11 6 S2,915 9 (18)S2,906 568 (61)S 3.13 Retained Earnings S3,630 (805)(2)267$3,090 (773)8 971$3,296 (793)15 (519)1S9M Accumulated other comprehensive Income (Loss)$ (4)(119)20 S (103)(14)(3)(6)S (126)117 (13)(585)(2)sff)Total$8,673 14 (805)4 7,886 (119)20 267 168$8,054 10 (773)(10)7,281 (14)(3)(6)971 948$8,229 676 (793)(4 )(163)117 (13)(585)(2)(519)(1.002)MA See Notes to Consolidated Financial statements beginning on page L-1.A-13 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31. 2002 Call Price per Shares Shares Amount (In share(a) Authorized(b) Outstandinatf) Millions)Not subject to Mandatory Redemption: 4.00% -5.00% S102-$110 1,525,903 608,150 $ 61 Subject to Mandatory Redemption: 5.90% -5.92% (c) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 51 Total subject to Mandatory Redemption (c) 84 Total Preferred stock 1145 December 31. 2001 Call Price per Shares shares Amount (In share(a) Authorized(b) Outstandino(f) Millions)Not subject to Mandatory Redemption: 4.00% -5.00% S102-S110 1,525,903 614,608 $ 61 subject to Mandatory Redemption: 5.90% -5.92% Cc) (d) 1,950,000 333,100 33 6.02% 7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 100,000 10 Total subject to Mandatory Redemption (c) 95 Total Preferred Stock S156 NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is S100 per share for all outstanding shares.(b) AS of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and 7,713,501 shares of $100,$25 and no par value preferred stock, respectively, that were authorized but unissued.(c) shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.(d) Not callable prior to 2003, after that the call price is $100 per share plus accrued dividends.(e) with sinking fund.(f) The number of shares of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares in 2001 and 209,563 shares in 2000.A-14 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries Maturity weighted Average Interest Rate December 31. 2002 Interest Rates 2002 at December 31.2001 December 31.2002 2001 (in millions)FIRST MORTGAGE BONDS (a)2002 -2004 2005 -2008 2022-2025 INSTALLMENT PURCHASE CONTRACTS (b)2002-2009 2011-2030 NOTES PAYABLE (c)2002-2021 SENIOR UNSECURED NOTES 2002 -2005 2006-2012 2032-2038 JUNIOR DEBENTURES 2025-2038 SECURITIZATION BONDS 2003-2016 OTHER LONG-TERM DEBT (d)Unamortized Discount (net)Total Long-term Debt outstanding Less Portion Due Within One Year Long-term Portion EQUITY UNIT SENIOR NOTES 2007 6.87%6.90%7.66%4.62%5.83%5.54%5.53%5.91%6.64%7.90%5.40%5.75%6.00%-7.85% 6.20%-8%6.875%-8.7% 3.75%-7.70% 1.35%-8.20% 3.732%-9.60% 2.12%-7.45% 4.31%-6.91% 6.00%-7-3/8% 7.60%-8.72% 6.00%-7.85% 6.20%-8%6-7/8%-8.80% 1.80%-7.70% 1.55%-8.20% 4.048%-9.60% 2.31%-7.45% 6.125%-6.91% 7.20%-7-3/8% 7.60%-8.72% $ 648 463 773 396 1,284 520 1,834 2,295 690 205 797 247 (32)10.120 1 633 S 1,246 699 850 446 1,234 217 1,910 1,727 340 618 258 (40)9, 505 1.095 L 8410 3.54%-6.25% 5.75%S-376 NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.(b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. variable rates generally relate to specified short-term interest rates.(d) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 9 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. Long-term debt outstanding at December 31, 2002 (includes Equity Unit senior Notes) is payable as follows: (in millions)2003 2004 2005 2006 2007 Later Years Unamortized Discount Total S 1,633 824 993 1, 611 1,081 4.386 10,528 32£10,9 A-15 AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Combined Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Goodwill and other Intangible Assets Merger Nuclear Plant Restart Rate Matters Effects of Regulation customer Choice and Industry Restructuring Commitments and contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans stock-Based compensation Business Segments Risk Management, Financial Instruments And Derivatives Income Taxes Basic and Diluted Earnings Per share Supplementary Information Power and Distribution Projects Leases Lines of credit and sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Minority Interest in Finance subsidiary Equity units Subsequent Events (unaudited) combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 5 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 15 Note 16 Note 17 Note 18 Note 19 Note 20 Note 21 Note 22 Note 23 Note 24 Note 25 Note 26 Note 27 Note 30 A-16 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted ouraudits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 3 to the consolidated financial statements, the Company adopted SFAS 142, 'Goodwill and Other Intangible Assets, effective January 1, 2002.As discussed in Note 13 to the consolidated financial statements, the Company recorded certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002./s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 A-17 L_MANAGEMENTS RESPONSIBILITY The management of American Electric Power Company, Inc. has prepared the financial statements and schedules herein and is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with accounting principles generally accepted in the United States of America, using informed estimates where appropriate, to reflect the Company s financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company s Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Companys established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP -independent auditors and the Companys internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the previous page.The auditors provide an objective, independent review as to management s discharge of its responsibilities insofar as they relate to the fairness of the Company s reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Companys internal control structure over financial reporting. A-18 AEP GENERATING COMPANY AEP GENERATING COMPANY Selected Financial Data INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant Year Ended December 31.2002 2001 2000 1999 1998 (in thousands) $213,281 $227,548 $228,516 $217,189 $224,146 207,152 220.571 220,092 211,849 215,415 6,129 6,977 8,424 5,340 8,731 3,681 3,484 3,429 3,659 3,364 2,258 2,586 3.869 2.804 3.149 ,$L52 $ 77875 $ ,94 $6J195 $ Ai December 31.2002 2001 2000 1999 1998 (in thousands) $652,213 358.174$648,254 337,151$-3-1-,10$642,302 315.566$36,736$640,093 295.065 ,$345,028$636,460 277. 855 Total Assets$349,729 $361,41 $374,602 A U $403 892 Common stock and Paid-in capital Retained Earnings Total Common shareholder's Equity$ 24,434 18.163$ 4259$ 24,434 13.76$ 3-8,19-5$ 24,434 9,722$ 30,235 3.673$ 36,235 2,770$ 900 Long-term Debt (a)Total Capitalization And Liabilities S_4i8QZ $4,793 $ 44,808 $ 48 44,79 UAJTZ9 $36 1 ,41 $374,602 $98 4 $403 1892 (a) Inc7uding portion due within one year.B-1 AEP GENERATING COMPANY Management s Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating Expenses Decrease Operating Expenses decreased 6% as follows: Operating Revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, l&M will purchase all of AEGCo's Rockport capacity unless it is sold to other utilities. A unit power agreement between AEGCo and KPCo expires in 2004.The KPCo unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. Results of Operations (dollars in thousands) ._ _ .._ ._ .., _ _ _ _ _ _ _ _ _Increase (Decrease) From Previous Year Amount %$(13,723) (13)1,899 17 565 6 137 1 Fuel other operation Maintenance Depreciation Taxes other Than Taxes Income Taxes Total Income (976)(1.321)S (3,41)(23)(46)(6)The decrease in Fuel expense reflects a decrease in generation and lower average fuel costs.Other Operation expense increased due to increased costs for employee benefits and property insurance. The increase in Maintenance expense can be attributed to shorter duration of maintenance outages for boiler inspection and repair in 2001.Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and personal property taxes reflecting a favorable change in the law which lowered the tax for Rockport Plant.Net Income decreased $323,000 or 4% as a result of limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant.The decrease in Income Taxes attributable to operations is primarily due to a decrease in pre-tax operating income and a change in estimate for state income tax accruals.Operating Revenues Decrease The decrease in Operating Revenues of$14,267,000 or 6% reflects a decrease in recoverable expenses, primarily fuel.B-2 AEP GENERATING COMPANY Statements of Income OPERATING REVENUES OPERATING EXPENSES: Fuel Rent -Rockport Plant Unit 2 other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Year Ended December 31.2002 2001 2000 (in thousands) $213.281 $227.548 $228,516 TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDITS INTEREST CHARGES NET INCOME 89,105 68,283 12,924 9,418 22,560 3,281 1.581 207,152 6,129 343 198 3,536 2.258.$ -752 102,828 68,283 11,025 8,853 22,423 4,257 2.902 220. 571 6,977 30 16 3,470 2.586$_zl875 102,978 68,283 10,295 9,616 22,162 3,854 2.904 220.092 8,424 6 17 3,440 3.869$ 7L984 Statements of Retained Earnings RETAINED EARNINGS JANUARY 1 NET INCOME CASH DIVIDENDS DECLARED RETAINED EARNINGS DECEMBER 31 See Notes to Financia7 Statements beginning on page L-1.Year Ended December 31.2002 2001 2000 (in thousands) $13,761 $ 9,722 $3,673 7,552 7,875 7,984 3 150 3.836 1.935 18&-63 $13 ,761 $4X7 B-3 AEP GENERATING COMPANY Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $637,095 $638,297 General 4,728 3,012 Construction work in Progress 10.390 6.945 Total Electric Utility Plant 652,213 648,254 Accumulated Depreciation 358,174 337.151 NET ELECTRIC UTILITY PLANT 294,039 311.103 OTHER PROPERTY AND INVESTMENTS 119 119 CURRENT ASSETS: cash and cash Equivalents -983 Accounts Receivable: Affiliated Companies 18,454 22,344 Miscellaneous -147 Fuel 20,260 15,243 Materials and supplies 4,913 4,480 Prepayments -244 TOTAL CURRENT ASSETS 43.627 43.441 REGULATORY ASSETS 4.970 5.207 DEFERRED CHARGES 6,974 1.471 TOTAL ASSETS S3A 4 29 $6134 see Notes to Financial Statements beginning on page L-1.B4 AEP GENERATING COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stock Par value $1,000: Authorized and outstanding 1,000 Shares $ 1,000 $ 1,000 Paid-in capital 23,434 23,434 Retained Earnings 18163 13761 Total Common shareholder s Equity 42,597 38,195 Long-term Debt 44.802 44,793 TOTAL CAPITALIZATION 87.399 82.988 OTHER NONCURRENT LIABILITIES 301 76 CURRENT LIABILITIES: Advances from Affiliates 28,034 32,049 Accounts Payable: General 26 7,582 Affiliated Companies 15,907 1,654 Taxes Accrued 2,327 4,777 Rent Accrued Rockport Plant Unit 2 4,963 4,963 other 1.111 3.48 TOTAL CURRENT LIABILITIES 52.368 54.506 DEFERRED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 111,046 116.617 REGULATORY LIABILITIES: Deferred Investment Tax credits 52,943 56,304 Amounts Due to Customers for Income Taxes 16.670 22.725 TOTAL REGULATORY LIABILITIES 69.613 79.029 DEFERRED INCOME TAXES 29.002 27,975 DEFERRED CREDITS -150 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES $349,729 $M1,341I See Notes to Financia7 statements beginning on page L-1.B-5 AEP GENERATING COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation Deferred Income Taxes Deferred Investment Tax Credits Amortization of Deferred Gain on sale and Leaseback -Rockport Plant Unit 2 Change in Certain Current Assets and Liabilities: Accounts Receivable Fuel, Materials and supplies Accounts Payable Taxes Accrued other Assets other Liabilities Net Cash Flows From operating Activities $ 7,552 S 7,875 $ 7,984 22,560 (5,028)(3,361)(5,571)4,037 (5,450)6,697 (2,450)(5,211)(2.295)11,480 22,423 (6,224)(3,414)(5,571)1,224 (4,738)(4, 597)(216)(569)(1.244)4,949 22,162 (5,842)(3,396)(5,571)1,392 6,486 (13,157)708 1,636 (404)11. 998 INVESTING ACTIVITIES Construction Expenditures FINANCING ACTIVITIES: Return of Capital to Parent Company change in short-term Debt (net)Change in Advances From Affiliates (net)Dividends Paid Net Cash Flows From (Used For)Financing Activities (5,298)(4,01-5)(3,150)(7.165)(6,868)3,981 (3.836)145 (5,190)(5,801)(24,700)28,068 (1.935)(4,368)Net Increase (Decrease) in cash and cash Equivalents Cash and cash Equivalents January 1 cash and cash Equivalents December 31 supplemental Disclosure: Cash Paid for interest net of capitalized amounts was and for income taxes was $7,884,000, $8,597,000 and respectively. (983)983$~ _(1,774)2,757$ 98 2,440 317$2,019,000, $1,509,000 and $3,531,000 $6,820,000 in 2002, 2001 and 2000, See Notes to Financial Statements beginning on page L-1.B-6 11, AEP GENERATING COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) COMMON STOCK EQUITY (a) $42.597 $38.195 LONG-TERM DEBT Installment Purchase Contracts City of Rockport (b)series Due Date 1995 A, 2025 (c) 22,500 22,500 1995 B, 2025 (c) 22,500 22,500 unamortized Discount (198) (207)TOTAL LONG-TERM DEBT 44.802 44,793 TOTAL CAPITALIZATION $87399 29 (a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There were no other material transactions affecting Common stock and Paid-in Capital in 2002, 2001 and 2000.(b) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant.(C) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006.See Notes to Financia 7 Statements beginning on page L-1.B-7 AEP GENERATING COMPANY Index to Combined Notes to Financial Statements The notes to AEGCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to AEGCo. The combined footnotes begin on page L-1.significant Accounting Policies Effects of Regulation Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 7 Note 9 Note 10 Note 11 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 B-8 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of AEP Generating Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 B-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES =AEP TEXAS CENTRAL COMPANY AND Selected Consolidated Financial Data SUBSIDIARIES 2002 Year Ended December 31.2001 2000 (in thousands) 1999 INCOME STATEMENTS DATA: operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements Gain (Loss) on Reacquired Preferred Stock$1,690,493 1.296.760 393,733 8,079 125.871 275,941 275,941$1,738,837 1,443.106 295,731 5,324 116.268 184,787 (2.509)182,278$1,770,402 1.463.304 307,098 7,235 124,766 189,567 189,567$1,482,475 1.188.490 293,985 8,113 114 380 187,718 (5 517)182,201 6,931 1998$1,406,117 1 123.330 282, 787 760 122.036 161,511 161,511 6,901 241 242 241 4 (2.763)Earnings Applicable To Common stock$_275704 1$_182L 06$ 172.507 L$_ 15-461Q Year Ended December 31.2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation And Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$5,625,736 2.405.492$320 -244$5'536P438 $ 187,898 (73,160)986.396$1- 1O1t 13A$ 5,942-2001$5,769,707 2.446.027$ 573,903 826,197$1,420QlQQ 2000 (in thousands) $5,592,444 2.297,189$ 573,904 792,219$ 5,951 1999$5,511,894 2.247,225$ 573,904 758.894-$-I 33-,79$5.95 1998$5,336,191 2.072.686$4,735,_ff $ 573,904 734. 387$1 1QWLZX CPL Obli ated, Mandatori 1y Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior subordinated Debentures of CPL Long-term Debt (a)Total capitalization And Liabilities $-13-6 Z 5-SI136 25Q$148,500$1,454,559 $154,5I41$5,467,01$4,735,656 (a) Including portion due within one year.C-1 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Managrement s Discussion and Analvsis of Results of Operations AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TCC s behalf byAEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TCC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TCC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TCC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC s sales as described below under"Results of Operations. In December 2002, AEP sold the affiliated REP to an unrelated third party who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP were classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income increased $94 million or 51 % primarily due to $262 million of revenues associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas which resulted in the loss of customers and reduced prices (see Note 8).In 2001, Income Before Extraordinary Item decreased $5 million or 3%, primarily resulting from a settlement of Texas municipal franchise fees and increased Maintenance expenses.Changes in Operating Revenues Increase (Decrease) From Previ ous Year (dollars in millions)2002 2001 Amount % Amount whol esal e El ectri ci ty*Energy Delivery*Sales to AEP S (1, 096.4) (90) S(29.9) (2)81.4 17 (5.6) (1)Affiliates 966.7 N.M. 4.0 11 Total 5(8.) (3) 5 31. 5) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful In 2002, Wholesale Electricity revenues decreased as a result of the elimination of TCCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins offset in part by the interchange cost reconstruction C-2 (ICR) adjustments (see Note 6). In 2001, the decrease in Wholesale Electricity revenues was primarily attributable to unfavorable wholesale power marketing and trading conditions. In 2002, Sales to AEP Affiliates revenue increased primarily due to increased revenues from the newly created affiliated REP.Although TCC sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue. Revenues for 2002 included $262 million of revenues, associated with recognition of stranded costs in Texas (see Note 8). Energy Delivery revenue also included revenues received for securitized assets beginning in 2002 (see Note 8).Chances in Operatinc ExDenses based on the current spot market price.Changes in natural gas prices affect TCC s fuel expense; however, they generally did not impact results of operations in 2001 and 2000 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.In 2002, the increase in Wholesale Electricity Purchased Power expense is due to higher MWH purchases from the market where we could purchase power at prices lowerthan our cost to produce. ICR adjustments also had the effect of increasing Wholesale Electricity Purchased Power expense and decreasing AEP Affiliates Purchased Power expense in 2002 (see Note 6).In 2001, Purchased Power increased overall largely due to higher natural gas prices.Although gas prices declined in 2001, they were higher during the first half of 2001 when TCC was making most of its purchases. In 2002, Other Operation expense decreased due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses.Increase (Decrease) From Previous Year A Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreci ati on And Amortization Taxes other Than Income Taxes Income Taxes Total V((dollars in millions) In 2002, Maintenance expense decreased 2002 2001 due to two scheduled '18 month interval mount % Amount % refueling outages for STP during 2001 that increased Maintenance expense above the:246.2) (50) SC58.8) C11) 2002 and 2000 levels. Also contributing to the decrease in 2002, and the increase in 83.5 65 C16.2) (11) 2001, was an increase in Maintenance 83.5* 65 (16.2) (l ) expense for scheduled major overhauls of (35.3) (60) 26.0 80 four power plants in 2001.(17.1) (5) 1.7 1-7 1 -I -tO'.i.) L.+/-+/-J +/-U. I IO In 2002, the increase in Depreciation and Amortization is attributable to the amortization 45.8 27 (10.4) (6) of regulatory assets that were securitized in 4. 6 5 14.4 19 the first quarter of 2002, offset by the 26.1 23 12.4 12 elimination of excess earnings expense in.46) (10) -A) C') 2002 under Texas Restructuring Legislation (see Note 8).la In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of fuel and decreased generation. The decrease in Fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. TCC used natural gas as fuel for 32% of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax, due to deregulation. In 2001, Taxes Other Than Income Taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees, and a new tax levied by the C-3 PUCT, the Texas System Benefit Fund Assessment. In 2002, the increase in Income Taxes is due to an increase in pre-tax income offset by changes in timing between book/tax accounting differences in state income taxes.In 2001 the increase in Income Tax expense is primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income.Other Changes In 2002, Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the energy related construction projects included in Nonoperating Income increased $34 million and $15 million in 2002 and 2001. The expenses associated with these projects included in Nonoperating Expenses increased$32 million and $14 million in 2002 and 2001.current cost to generate electricity, TCC proposed in September 2002 to "inactivate various, high-cost gas fired generating facilities. In the third quarter 2002, TCC recorded an impairment charge of approximately $95.6 million (pre-tax) related to these plants and recorded approximately $4.0 million (pre-tax) for severance charges.Both of these charges were deferred and recorded in RegulatoryAssets Designated for or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 8). In the fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional plant impairments, fuel inventory and materials and supplies, and an additional $1.5 million pre-tax charge was recorded related to severance charges (see Note 13) related to the Inactivated plants. The entire $23.1 million was also deferred and recorded in Regulatory Assets Designated for or Subject to Securitization. In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax non-operating income.In 2002, Interest Charges increased primarily due to higher levels of outstanding debt (see TCC s schedule of Long-term Debt and Consolidated Statements of Capitalization for further information). In 2001, the decrease in interest charges was attributable to lower average interest rates associated with short-term and long-term debt.Extraordinary Loss The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas.Impairment As a result of TCC s recent abilityto purchase electricity at a significantly lower price than its C-4 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP A ffiliates TOTAL OPERATING REVENUES$ 127,502 554,547 1.008.444 1.690.493 OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES 245,834 211,358 23,406 304,094 63,392 214,162 95,500 139.014 1. 296, 760$1,223,893 473,182 41.762 1. 738. 837 492,057 127,816 58,641 321,227 71,212 168,341 90,916 112.896 1.443.106$1,253,836 478,814 37.752 1.770.402 550,903 144,021 32,591 319,539 60,528 178,786 76,477 100.459 1.463. 304 OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)393,733 53,141 41,910 3,152 295,731 22,552 17,626 (398)307,098 5,830 3,668 (5,073)INTEREST CHARGES 125. 871 116.268 124,766 INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567 EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001)NET INCOME 275,941 (2.509)182,278 242 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS GAIN ON REACQUIRED PREFERRED STOCK 241 241 4 EARNINGS APPLICABLE TO COMMON STOCK$ -18Z-16 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 (in thousands) $182,278 2000$189,567 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME$275,941 (36)(73,124)$18 2- dl1 S1W2,WA The common stock of TCC is owned by a wholly owned subsidiary of AEP.See Notes to Financia7 statements beginning on page L-1.C-5 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31.2002 2001 2000 (in thousands) BEGINNING OF PERIOD $826,197 $792,219 $758,894 NET INCOME 275,941 182,278 189,567 DEDUCTIONS (ADDITIONS): Capital stock Gains (4) --Cash Dividends Declared: Common stock 115,505 148,057 156,000 Preferred stock 241 242 241 other -1 1 BALANCE AT END OF PERIOD 26 $ 6197 $792,219 The common stock of TCc is owned by a wholly owned subsidiary of AEP.see Notes to Financial statements beginning on page L-1.C-6 --AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Nuclear Fuel Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS SECURITIZED TRANSITION ASSETS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: General Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued Utility Revenues Energy Trading and Derivative Contracts Prepayments and other current Assets TOTAL CURRENT ASSETS REGULATORY ASSETS REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION NUCLEAR DECOMMISSIONING TRUST FUND DEFERRED CHARGES TOTAL ASSETS See Notes to Financial Statements beginning on page L-1.$2,903,942 698,964 1,296,731 258,386 200,947 266.766 5,625,736 2.405.492 3.220.244 3.977 734. 591 4.392 85,420 113,543 121,324 (346)32,563 51,593 27,150 22,493 2.133 455.873 458. 552 336.444 98.474 43,891 Sig56 E438$3,169,421 663,655 1,279,037 241,137 169,075 5,769,707 2.446,027 3. 323.680 47,950 28 039 10,909 38,459 6,249 (186)38,690 55,475 34,480 2.742 186 818 226. 812 959,294 98.600 21.837$4,9303 C-7 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock $25 Par Value: Authorized 12,000,000 shares outstanding 2,211,678 shares at December 31, 2002 6,755,535 shares at December 31, 2001 Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock CPL obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of CPL Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: short-term Debt Affiliates Long-term Debt Due within one Year Advances from Affiliates (net)Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$ 55,292 132,606 (73,160)986 396 1,101,134 5,942 136,250 1,209.434 2.452.760 74.572 650,000 229,131 126,711 72,199 36,242 666 24,791 51,205 19,811 36. 698 1.247.454 1.261.252 117.686 1,713 201.001 S5,356 A438$ 168,888 405,015 826.197 1,400,100 5,952 136,250 988.768 2,531.070 10.905 265,000 354,277 65,307 49,301 26,744 83,512 23,715 40,987 18,076 926.919 1,163.795 122.892 17,675 119.774$4 1 9,83A3D C-8 --l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income Adjustments to Reconcile Net Income to Net cash Flows from Operating Activities: Depreciation and Amortization Extraordinary Loss on Reacquired Debt Deferred Income Taxes Deferred Investment Tax credits Mark-toMarket Energy Trading and Derivative Contracts change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Interest Accrued Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission coordination Agreement settlement Texas wholesale Clawback (see Note 7)change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: Construction Expenditures Proceeds From Sales of Property and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: Issuance of Long-term Debt change in short-term Debt Affiliate (Net)Retirement of Common stock Retirement of Preferred stock Retirement of Long-term Debt change in Advances from Affiliates (net)special Deposit for Reacquisition of Long-term Debt Dividends Paid on Common stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities $275,941 $182,278 $189,567 214,162 113,655 (5,206)(1,558)(189,999)(4,899)27,490 (27,150)(6,167)(58,721)16,455 (262,000)(534)56.024 147.493 (151,645)143 (151. 502)797,335 650,000 (386,005)(6)(639,492)(227,566)(115, 505)(241)78.520 168,341 2,509 (72,568)(5,208)(12,048)52,862 (18,215)(2,502)(55, 311)27,986 179,866 10,767 11,163 469,920 (193,732)(354)(194.086)260,162 (475,606)84,565 (148,057)(242)(279,178)178,786 16,263 (5,207)8,191 (32,902)8,680 11,494 45,873 14,405 (96,872)15,519 589 12 .243 366,629 (199,484)(199.484)149,248 (151,440)(52,446)50,000 (156,000)(249)(160.887)Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1 Cash and cash Equivalents December 31 74,511 10.8909 (3,344)14.253 SLQ 3Q9 6,258 7.995 illw53 supplemental Disclosure: Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and for income taxes. was$95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and 2000,respectively. see Notes to Financial statements beginning on page L-1.C-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) S1.10o.134 S1.400.100 COMMON SHAREHOLDER S EQUITY (a)PREFERRED STOCK 3,035,000 authorized shares, 5100 par value Not Subject to Mandatory Redemption: call Price -December 31, Number of shares Redeemed series 2002 Year Ended December 31. Dec 2002 2001 2000 Shares outstanding
- ember 31. 2002 4.00% S105.75 100 --41,938 4,194 4.20% 103.75 ---17,476 1.748 Total Preferred stock 5.942 TRUST PREFERRED SECURITIES:
TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of TCC, 8.00%due April 30, 2037 136.250 LONG-TERM (See schedule of Long-term Debt): First Mortgage Bonds 152,353 Securitization Bonds (a) 796,635 Installment Purchase Contracts 489, 577 Senior unsecured Notes -Less Portion Due within One year (229.131)Long-term Debt Excluding Portion Due within one Year 1.209.434 TOTAL CAPITALIZATION (a) In February 2002, TCC issued securitization bonds. S386 million of the proceeds 4,543,857 shares of common stock.See Notes to Financial Statements beginning on page L-1.4,204 1,748 5.952 136. 2 50 614,200 489,568 150,000 (265.000)988. 768 was used to retire C-1 0 i -AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) December 31, 2002 2001 (in thousands) % Rate Due 7.25 2004 7.50 2002 6-7/8 2003 7-1/8 2008 7.50 2023 6-5/8 2005 Total October 1 December 1 February 1 February 1 April 1 July 1 S 27,400 16,418 18,581 17,996 71. 958$100,000 115,000 49,200 75,000 75,000 200 000 ikQu Q% Rate Due Matagorda County Navigation District, Texas: 6.00 2028 July 1 6-1/8 2030 May 1 3.75 2030(a) May 1 4.00 2030(a) May 1 4.55 2029(a) Nov .Guadalupe-Blanco River Authority District, Texas: (b) 2015 November 1 Red River Authority District, Texas:$120,265 60,000 111,700 50,000 100,635 S120,265 60,000 111,700 50,000 100,635 First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Securitization Bonds outstanding were as follows: 40,890 40,890 Final Payment Maturity Rate Date Date 3.54 1/15/2005 1/15/2007 5.01 1/15/2008 1/15/2010 5.56 1/15/2010 1/15/2012 5.96 7/15/2013 7/15/2015 6.25 1/15/2016 1/15/2017 unamortized Discount Total December 31.2002 2001 (i~nthousands) 6.00 2020 June 1 6,330 6,330 unamortized Discount (243) (252)Total S4O9,577 (a)installment Purchase contract provides for bonds to be tendered in 2003 for 3.75% and 4.00% series and in 2006 for 4.55% series.Therefore, these installment purchase contracts have been classified for payments in those years.(b) A floating interest rate is determined monthly. The rate on December 31, 2002 was 1.7%.Under the terms of the installment purchase contracts, TCC is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: S128,950 154,507 107,094 214,927 191,857 (700)5796>6i5$In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 2002 February 22 Cc)Total December 31.2002 2001 (in thousands) $ -S150.000 S -$150.AlOO (c) A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.56%.C-11 At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 229,131 75,951 121,937 152,900 52,729 806.860 1,439,508 (943)51,438,56 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of TCC.C-12 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to TCC s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to TCC. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Merger Rate Matters Effects of Regulation customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Asset Impairment and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 C-1 3 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas Central Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Companyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31,2002 in conformity with accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 C-14 -J al AEP TEXAS NORTH COMPANY AEP TEXAS NORTH COMPANY Selected Financial Data 2002 Year Ended December 2001 2000 (in thousands) 31 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income (Loss) Before Extraordinary Item Extraordinary Loss Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$ 450,740 442.869 7,871 (703)20,6845 (13,677)(13,677)104$556,458 523.068 33,390 2,195 23, 275 12,310 12,310 104$571,064 518.723 52,341 (1,675)23,216 27,450 27,450 104 1999$445,709 391.910 53,799 2,488 24,420 31,867 (5.461)26,406 104 1998$424,953 365,677 59,276 2,712 24.263 37,725 37,725 104$ 37,621$ (13.781)S 34-6 S 26,302 2002 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric utility Plant Total Assets Common stock and Paid-in Capital Accumulated other Comprehensive Income (LosS)Retained Earnings Total Common Shareholder's Equity$1,201,747 521.792 S 679,955$ 877,175$ 139,565 (30,763)71.942$1&80,744 2001$1,260,872 546,162$ 714,710$ 139,565 105.970$_241S53-5 December 31.2000 (in thousands) $1,229,339 515,041$ 714,298 51,087. 504$ 139,565 122,588$_262 153 1999$1,182,544 495.847 5 686,697$ 861,205$ 139,565 113,242 S_252 s807 1998$1,146,582 473.503$ 673,079$,819,446 S 139,565 114.940 S 254,505 Cumulative Preferred stock: Not subject to Mandatory Redemption S 2,367 Long-term Debt (a) $ 132,50 Total Capitalization And Liabilities S 877L21Z5 S 255,967 255.7$S_22 _N S 6 8 L&6t4875 S1.087.iOA 5 8612,05 S _819A446 (a) Including portion due within one year.D-1 AEP TEXAS NORTH COMPANY Manaaement s Narrative Analysis of Results of ODerations AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas.Wholesale power marketing activities are conducted on TNC s behalf byAEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TNC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entitythatwas an AEP subsidiary (not owned by or consolidated with TNC) was sold in December 2002 (see Note 12).Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TNC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC s sales as described below under"Results of Operations. In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale, during 2002, sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP will be classified as Wholesale Electricity or Energy Delivery.Results of Operations In 2002, Net Income decreased $26.0 million or 211 % primarily due to a $38.1 million long-lived asset impairment charge ($24.8 million net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a$4.7 million impairment charge ($3.1 million net of tax) related to the abandonment of a wind-powered generation facility (see Note 13).Changes in Operatina Revenues Increase (Decrease) From Previous Year (in millions) h wholesale Electricity* Energy Delivery*sales to AEP S(231. 7)(95.7)(63)(57)Affiliates 221.7 N.M.Total ()05.7) (19)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.N.M. = Not Meaningful Wholesale Electricity revenues decreased as a result of the elimination of TNCs retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins, partially offset by the ICR adjustments (see Note 6).D-2 Sales to AEP Affiliates increased primarily due to increased revenues from the newly created affiliated REP. Although TNC sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues decreased due to lower prices for power sold to the affiliated REP.Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue.Changes in Operating Expenses Increase (Decrease) From Previous Year (in millions) %Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total S(76.7)10.0 (19 .1)(6.3)42.9 (7.1)(5.8)(18.1)gun 2)(43)14 (34)(6)N.M.(14)(21)N.M.(15)electricity at a significantly lower price than its current cost to generate electricity, TNC proposed in September 2002 to Inactivate various, high-cost gas fired generating facilities. TNC recorded an impairment charge in the third quarter 2002 of approximately $34.2 million related to these plants, which was recorded in Asset Impairments expense. In the fourth quarter 2002, an additional asset impairments charge of $3.9 million was also recorded in connection with these plants, along with a$4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, a $1.2 million charge associated with fuel inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (recorded in Other Operations) was recorded in the fourth quarter of 2002 related to the"inactivated plants.Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation and the elimination of regulatory asset amortization that ended in 2001.The decrease in Taxes Other Than Income Taxes is primarily a result of one time 2001 assessments and a decrease in the gross receipts tax due to deregulation. The decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the impairment of various generating facilities. Other Changes Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the aforementioned energy related construction projects included in Nonoperating Income increased $45.5 million in 2002. The expenses associated with these projects included in Nonoperating Expenses increased $43.0 million in 2002.Interest Charges declined primarily due to lower interest rates.N.M. = Not Meaningful Fuel expense decreased due to a decrease in the average unit cost of fuel and decreased generation required due to decreased energy sales. TNC used natural gas as fuel for 42%of its generation in 2002. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect TNC s fuel expense;however, they generally did not impact results of operations in 2001 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002.The net decline in total Purchased Power expense in 2002 was mainly due to both reduced MWHs purchased and reduced prices, partially offset by ICR adjustments (see Note 6).Other Operation expense decreased slightly in 2002 due to lower factoring and transmission expenses, offset in part by a$1.4 million write-down of material and supply inventory associated with the impaired plants.As a result of TNC s recent ability to purchase D-3 it, AEP TEXAS NORTH COMPANY Statements of Operations Year Ended December 31, 2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Asset Impairments Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Tax Expense (Credit)TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX CREDIT INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$136,962 73,353 240,425 450.740 100,466 80,391 37,582 104,960 42,898 22,295 43,620 22,471 (11.814)442.869 7,871 53,763 54,755 (289)20.845 (13,677)104 2001 (in thousands) $368,741 169,036 18.681 556.458 177,140 70,395 56,656 111,248 22,343 50,705 28,319 16.262 523.068 33,390 12,199 10,695 (691)23.275 12,310 104> t12 20l6$376,206 176,204 18,654 571,064 183,154 68,080 57,773 93,078 21,241 55,172 25,321 14,904 518.723 52,341 9,530 12,664 (1,459)23.216 27,450 104$ 27,3A6 2000 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) $(13,677) $12,310 $27,450 NET INCOME (LOSS)OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(15)-(30.74)i$12 1 3i The common stock of TNC is owned by a wholly owned subsidiary of AEP.see notes to Financial statements beginning on page L-1.D-4 AEP TEXAS NORTH COMPANY Statements of Retained Eaminqs Year Em 2002 (in BEGINNING OF PERIOD $105,970 i NET INCOME (LOSS) (13,677)DEDUCTIONS: cash Dividends Declared: Common Stock 20,247 Preferred stock 104 BALANCE AT END OF PERIOD 7192A2 The common stock of TNC is owned by a who77y owned subsidiary of AEP.see notes to Financial Statements beginning on page L-1.Jed December 31.2001 2000 thousands)
- 122,588 $113,242 12,310 27,450 28,824 104$1I0,7=0 18,000 104 D-5 AEP TEXAS NORTH COMPANY Balance Sheets December 31, 2002 2001 (in thousands)
ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Allowance for Uncollectible Accounts Fuel Inventory Materials and Supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS See Notes to Financia7 Statements beginning on page L-1.$ 353,087 254,483 445,486 111,679 37.012 1,201,747 521.792 679 955 1,213 2.248 1,219 62,660 43,632 (5,041)12,677 9,574 6,829 4,130 1,070 136.750 45,097 11 912$877.175$ 443,508 250,023 431,969 112,797 22.575 1,260,872 546.162 714,710 24.933* 8.327 2,454 18,720 8,656 (196)8,307 11,190 10,240 966 60,337 54,122 2.446_$_8_64,875 D-6 AEP TEXAS NORTH COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock $25 Par value: Authorized 7,800,000 Shares outstanding 5,488,560 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred Stock Not subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: short-term Debt Affiliates Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES see Notes to Financia7 statements beginning on page L-1.$137,214 2,351 (30,763)71.942 180,744 2,367 132. 500 28, 861 125,000 80,407 32,714 76,217 117 3,697 2,776 3,801 17.414 342,143 117, 521 21.510 557 50,972$137, 214 2,351 105.970 245,535 2,367 220,967 468.869 6,296 35,000 50,448 33,782 11,388 4,191 17,358 4,762 12,402 9. 824 179 155 145.049 22,781 52 250 37.475$87,17 D-7 AEP TEXAS NORTH COMPANY Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income (Loss)Adjustments to Reconcile Net Income to Net Cash Flows From operating Activities: Depreciation and Amortization writedown of Utility Assets writedown of wind Farm Assets Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement change in other Assets Change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES: Construction Expenditures sales Proceeds and other Net Cash used For Investing Activities FINANCING ACTIVITIES: Retirement of Long-term Debt change in short-term Debt Affiliated (net)Change in Advances from Affiliates (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net Cash Flows From (used For) Financing Activities $(13,677) $ 12,310 $ 27,450 43,620 38,154 4,744 (12,275)(1,271)(1,127)(74,071)(2,754)(6,829)63,761 (13,661)14,169 (16,928)16, 514 38. 369 (43,563)150 (43,413)50,705 (11,891)(1,271)(3,506)24,844 3,187 (42,604)(1,543)32,505 (1,432)11,056 72. 360 (39,662)(127)(39.789)55,172 8,164 (1,271)2,590 (1,445)8,478 28,393 6,443 (53,841)15,465 2,549 (3.869)94,278 (64,477)(64,477)(130,799)125,000 29,959 (20,247)(104)3 809 (8,130)(28,824)(104)(37,058)(48,000)37,170 (18,000)(104)(28.934)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents at Beginning of Period Cash and cash Equivalents at End of Period (1,235)2,454$-1,2-19 (4,487)6.941 i__2,54 867 6.074 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $19,934,000 $19,279,000 and$19,088,000 and for income taxes was $15,544,000, $21,997,000 and ($906,000) in 2002, 2001 and 2000 respectively. see Notes to Financia7 statements beginning on page L-1.D-8 AEP TEXAS NORTH COMPANY Statements of Capitalization December 31.2002 2001 (in thousands) $180.744 S245.535 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 810,000 Call Price December 31, Number of Shares Redeemed Series 2002 Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption: 4.40% $107 --1 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 Statements beginning on page L-1.shares outstanding December 31. 2002 23,672 2,367 2,367 88,190 44,310 132. 500 211,657 44,310 (35 000)220.967 D-9 AEP TEXAS NORTH COMPANY Schedule of LonQ-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousaniis-Y % Rate Due 6-7/8 2002 October 1 S -7 2004 October 1 18,469 6-1/8 2004 February 1 24,036 6-3/8 2005 October 1 37,609 7-3/4 2007 June 1 8,151 unamortized Discount (75)Q8 S 35,000 40,000 40,000 72,000 25,000 (343)i2IL-6S Under the terms of the installment purchase contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) 2003 $ -2004 42,505 2005 37,609 2006 -2007 8,151 Later Years 44 310 Principal Amount 132,575 Less: unamortized Discount C75)Total S First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due Red River Authority of Texas: 6.00 2020 June 1 December 31.2002 2001 (in thousands) 544310 S44,31 D-10 AEP TEXAS NORTH COMPANY Index to Combined Notes to Financial Statements The notes to TNC s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to TNC. The combined footnotes begin on page L-1.Combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued operations Note 12 Asset Imapairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of credit and Sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Jointly owned Electric utility Plant Note 28 Related Party Transactions Note 29 D-11 i INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of AEP Texas North Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 D-1 2 APPALACHIAN POWER COMPANY AND SUBSIDIARIES I APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data I .n" 11 IdnIA IJ .IIU 1* J.1 ... I -.----2002 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Gain Net Income Preferred stock Dividend Requirements Earnings Applicable to common Stock$1,814,470 1,512,407 302,063 20,106 116.677 205,492 205,492 2.897$ 202,195 2001$1,784,259 1.509.273 274,986 6,868 120,036 161,818 161,818 2.011$ 159&0QZ 2000 (in thousands) $1,759,253 1.558.099 201,154 11,752 148.000 64,906 8.938 73,844 2,504 1999$1,586,050 1,344,814 241,236 8,096 128.840 120,492 120,492 2.706 1998$1,672,244 1.443.701 228, 543 (8,301)126.912 93,330 93,330 2.497 December 31, 2002 2001 2000 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant 1999$5,262,951 2.079.490$5,895,303 2.424.607$5,664,657
- 2. 296. 481$5,418,278
- 2. 188. 796 3229 ,482$6.522 l 9S 1998$5,087,359 1.,984. 856 SI-1MA61 14.35Z2 Total Assets Common Stock and Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Total Cumulative Preferred Stock_4 &62.7 847 V4,047,038
$ 977,700 (72,082)260,439 ,166 Q5Z$ 976,244 (340)150, 797 I 1,12-6 7 0-$ 975,676 120, 584$1.,096,260Q $ 974,717 175. 854$ 924,091 179.461$103A52$ 17,790 $ 17,790 10.860 10,860$ 17,790 10,860$ 28.650$1,605,818 $ 18,491 20,310$1__3 Oi t1<6 65,$ 19,359 22.310 Long-term Debt (a)obligations under Capital Leases (a)Total Capitalization And Liabilities IL,55-6-55-9 _$It55L455 Si__5d751z L-3i,5&89 t{A,621T4~ $ 46,281$ 64,645$4Z482,78$65 57255$4I,Q4ZQ38 (a) Including portion due within one year.E-1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operation APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 retail customers in southwestern Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. APCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs.The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs.Results of Operations Net Income increased $44 million or 27% in 2002 due to higher retail sales resulting from increased generation, weather related electricity demands and reductions in Maintenance expense. Most significantly, the Mountainer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased $10 million as a result of a reduction in trading incentive compensation recorded in Nonoperating Expenses offset in part by decreased power trading gains recorded in Nonoperating Income.Net Income increased $88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000.In February 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in net income was growth in and strong performance by the wholesale electricity business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales.Operating Revenues Operating Revenues increased $30 million or 2% in 2002 as a result of weather related demand and increased generation resulting from availablility of plants previously down for maintenance coming back online. An increase of $25 million, or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power Pool transactions. Changes in components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions)2002 2001 Amount % Amount %$16.0 2 S(11.7) (1)(1.0) -20.1 3 wholesale El ectri ci ty*Energy Delivery*Sales to AEP Affiliates Total Revenues 15.2 5302 9 2 16.6 L25 0 11 1*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Operating Revenues for 2002 increased as a result of an increase in generation and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in residential and commercial sales due to warmer weather during July and September. Sales to AEP affiliates increased for the year due to an E-2 increase in generation capacity and power available to be delivered to AEP Power Pool.These increases were partially offset by flat industrial sales as recessionary conditions continued into 2002.The year 2001 saw a decrease in kilowatt hour sales to industrial customers. This decrease was due to the economic recession. In the fourth quarter, sales to residential and commercial customers declined, reflecting recession-related reductions in demand.The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP Power Pool transactions. As the quantity of energy sold by the AEP Power Pool rose, APCo s contribution of energy to the Pool rose, accounting for the increase in APCo s revenues from Sales to AEP Affiliates. Operating Expenses Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Power expenses were offset by decreases in power purchases from AEP Affiliates due to increases in APCo generation and availability as plants previously down for maintenance resumed operations. The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity purchased power expense and depreciation and amortization expenses.Changes in the components of Operating Expenses are as follows: Increase (Decrease) From Previous Year (dolTlars in millions)2002 2001 Amount % Amount %Fuel S 79.4 23 S (17.6) (5)of an increase in APCo generation. Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability in 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. Wholesale Electricity Purchases increased for 2002 as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. Electricity purchased power expense increased in 2001 due to increases in wholesale electricity prices and as a result of the previously mentioned plant outages.The decrease for 2002 in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability. Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo s MLR.Other Operation expense increased in 2002 mainly due to severance expenses related to the sustained earnings initiative plan, a reduction in the gains recorded on the dispositions of S02 emission allowances, and increased insurance premiums and other employee benefit costs. These increases were offset by reduced trading overhead expenses as a result of reduced staffing and weaker market conditions; a decrease in transmission equalization charges caused by a reduction in APCo s MLR ratio; and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. Additionally, the decrease was the result of a gain recorded on the disposition of S02 emission allowances offset in part by increased wholesale power trading incentive compensation expense.The decrease in Maintenance expense in 2002 is primarily due to previously discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in the year 2001.wholesale Electricity Purchases 15.0 36 AEP Affiliate Purchases (112.3) (32)other operation 8.9 3 Maintenance (10.2) (8)Depreciation and Amortization 8.9 5 Taxes other Than Income Taxes (4.6) (5)Income Taxes 18.0 19 Total __3.1 -17.4 70 (8.9) (3)(18.6) (7)7.9 -6 17.3 11 (11.8)(34. 5)(11)(27)(3)Fuel expense increased for 2002 as a result E-3 Depreciation and Amortization expense increased during 2002 due to increased amortization for the net generation-related regulatory assets related to the Companys West Virginia jurisdiction which were assigned to the distribution portion of the Companys business and are being recovered through regulated rates. Investment in production plant in service, primarily equipment related to emission control, contributed to the increase in depreciation and amortization expense.Depreciation and Amortization expense increased in 2001 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets in the Virginia and West Virginia jurisdictions. Additional investments in distribution and transmission plant also contributed to the increases in depreciation and amortization expense in 2001. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were assigned to the energy delivery businesss regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates.trading gains driven by a decline in market prices. Nonoperating Expenses decreased as a result of decreased trading incentives. The increase in Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable increases in the level of activity in the wholesale business s trading transactions outside of the AEP System s traditional marketing area.Interest Charges Interest Charges for 2002 decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000.The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily to a decrease in municipal license tax. The municipal license tax was replaced by the Virginia consumption tax. The municipal license tax was imposed on APCo and the Virginia consumption tax is imposed on the customer with APCo acting as collector agent.The decrease in Taxes Other Than Income Taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state.The increase in Income Taxes for 2002 was due to an increase in pre-tax income. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income.Nonoperating Income and Nonoperating Expenses The Nonoperating Income decrease for 2002 was due primarily to a decrease in net power E-4 '!APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates Total Operating Revenues OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total operating Expenses OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (BENEFIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY GAIN DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS $1,'1.Year Ended December 3 2002 2001 (in thousands) )33,904 $1,017,938 594,089 595,036 186.477 171,285 314.470 1.784.259 430,963 57,091 234,597 269,426 122,209 189,335 95,249 113.537 1,512.407 302,063 29,278 11,783 (2,611)116.677 205,492 205,492 2.897 L.351,557 42,092 346,878 260,518 132,373 180,393 99,878 95. 584 1,509.273 274,986 49,507 41,500 1,139 120.036 161,818 161,818 2.011 2000$1,029,657 574,918 154.678 1.759.253 369,161 24,720 355,774 279,114 124,493 163,089 111,692 130.056 1.558.099 201,154 31,204 16,329 3,123 148.000 64,906 8.938 73,844 2.504 EARNINGS APPLICABLE TO COMMON STOCK-$ZLn-A0 Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME $205,492 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge (1,580)Minimum Pension Liability (70,162)COMPREHENSIVE INCOME $13,50 see Notes to Financia7 Statements beginning on page L-1.$161,818 $73,844 (340)S161,AI A E-5 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31.2002 2001 2000 (in thousands) $150,797 $120,584 $175,854 205.492 161,818 73,844 356.289 282.402 249,698 Retained Earnings January 1 Net Income Deductions: cash Dividends Declared: Common stock Cumulative Preferred Stock: 4-1/2% series 5.90% Series 5.92% Series 6.85% series Total cash Dividends Declared capital Stock Expense Total Deductions Retained Earnings December 31 See Notes to Financia7 Statements beginning on page L-1.92,952 801 278 364 94,395 1.455 95.850$260,4139-129, 594 801 278 364 131,037 568 131.605$150, 797 126,612 811 307 364 289 128,383 731 129.114 E-6 --APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmi ssion Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and cash Equivalents Accounts Receivable: Customers Affiliated Companies Mi scellaneous Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Accrued utility Revenues Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial Statements beginning on page L-1.$2,245,945 1,218,108 1,951,804 272,901 206.54 5 5 ,895,303 2,424.607 3,470.696 54.653 115,748 4,285 132,266 122,665 28, 629 (13,439)53,646 59,886 30,948 94,238 13.396 526.,520 395.,553 64. 677$2,093,532 1,222,226 1,887,020 257,957 203,922 5, 664 ,657 2. 296. 48.3. 368. 176 53. 736 119,638 13,663 113,371 63,368 11,847 (1,877)56,699 59,849 30,907 137,742 16.018 501.587 397. 383 42, 265 E-7 APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock No Par value: Authorized 30,000,000 shares outstanding 13,499,500 Shares Paid-in Capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareowner s Equity Cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Taxes Accrued Customer Deposits Interest Accrued Energy Trading and Derivative Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.$ 260,458 717,242 (72,082)260.439 1,166,057 17,790 10,860 1,738,854 2,933,561 173.438 155,007 39,205 141,546 98,374 29,181 26,186 22,437 69,001 79. 832 660.769 701.801 33.691 44.517 80,070$4,62L,847 $ 260,458 715,786 (340)150.797 1,126,701 17,790 10,860 1.476. 552 2.631.903 84,104 80,007 291,817 127,597 84,518 55,583 13,177 21,770 121,161 79.089 874.719 703. 575 38,328 60. 518 89, 638 A4-82, 25 E-8 APPALACHIAN POWER COMPANY AND SUBSIDIARIES consolidated Statements of Cash Flows Year Ended December 2002 2001 (in thousands) 31.2000 OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Power Supply Costs (net)Mark-to-Market of Energy Trading Contracts Provision for Rate Refunds Extraordinary Gain Change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Revenue Refunds Accrued Incentive Plan Accrued Disputed Tax and Interest Related to COLI change in operating Reserves Rate Stabilization Deferral change in other Assets change in other Liabilities Net Cash Flows From Operating Activities INVESTING ACTIVITIES: Construction Expenditures Proceeds From sales of Property and other Net Cost of Removal and Other Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: Issuance of Long-term Debt Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Change in Advances From Affiliates Dividends Paid on Common stock Dividends Paid on cumulative Preferred Stock Net cash Flows used For Financing Activities $ 205,492 189,335 16,777 (4,637)6,365 (21, 151)(83,412)3,016 (41)27,805 (26,402)(858)(3,190)(43,337)14,948 280,710$ 161,818 180, 505 42,498 (4,765)1,411 (68,254)134,099 (19,957)35,592 (45,073)(7,675)(2,451)(5,358)19,418 (27.954)393. 854$ 73,844 163,202 8,602 (4,915)(84,408)(1,843)(4,818)(8,938)(166,911)18,487 (13,081)159,369 14,220 181 10,662 72,440 (19,770)75,601 (13,021)9.817 288. 720 (276, 549)1,074 (275.475)647,401 (315,007)(252,612)(92,952)(1.443)(14,613)(306,046)1,182 (8.434)(313.298)124,588 (175,000)(191,495)300,204 (129,594)(1.443)(72.740)(199,285)159 (7.500)(206. 626)74,788 (9,924)(136,166)68,015 (8,387)(126,612)(1.938)(140,224)Net Increase (Decrease) in cash and Cash cash and cash Equivalents January 1 cash and cash Equivalents December 31 Equivalents (9,378)13.663$ 4,285 7,816 5 $ 847 (58,130)63.977$ A Z supplemental Disclosure: Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000 and$124,579,000 and for income taxes was $125,120,000, $56,981,000 and $63,682,000 in 2002, 2001 and 2000, respectively. There were no noncash acquisitions under capital leases in 2002. In 2001 and 2000, non cash acquisitions under capital leases were $2,510,000 and $14,116,000, respectively. see Notes to Financia7 Statements beginning on page L-1.E-9 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) S1.166.057 $1.126.701 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: No par value -authorized shares 8,000,000 call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not subject to Mandatory Redemption (b): 4-1/2% $110 6 -7,011 subject to Mandatory Redemption (b): 5.90% cc) --10,000 5.92% Cc) _ _ -shares Outstanding December 31. 2002 177,899 47,100 61, 500 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Junior Debentures other Long-term Debt Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 17.790 4,710 6.150 10.860 489,697 235,027 1,166,609 2,528 (155.007)1.738.854 17.790 4,710 6.150 10.860 639,365 234,904 518,247 161, 507 2,536 (80.007)1.476.552 52,631,903 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.(b) The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date.(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90%series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirement. see Notes to Financial statements beginning on page L-1.E-1 0 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 7.38 2002 7.40 2002 6.65 2003 6.85 2003 6.00 2003 7.70 2004 7.85 2004 8.00 2005 6.89 2005 6.80 2006 8.50 2022 7.80 2023 7.15 2023 7.125 2024 8.00 2025 unamortized Total August 15 '-December 1-May 1-June 1-November 1-September 1-November 1-May 1-June 22-March 1-December 1-May 1-November 1-May 1-June 1 Discount S -30,000 21,000 50,000 50,000 30,000 100,000 70,000 30,237 20,000 45,000 45,000-1C 540)$ 50,000 30,000 40,000 30,000 30,000 21,000 50,000 50,000 30,000 100,000 70,000 30, 237 20,000 45,000 45,000 (1.872)M69,36 Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands) First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. X Rate Due (a) 2003 August 20 S 125,000 5125,00 7.45 2004 -November 1 50,000 50,00 4.80 2005 June 15 450,000 -4.32 2007 November 12 200,000 -6.60 2009 -May 1 150,000 150,00 7.20 2038 -March 31 100,000 100,00 7.30 2038 -June 30 100,000 100,00 unamortized Discount 8 391 6.75 Total VIA609 S51,2 (a) A floating interest rate is determined monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, respectively. 0 0 0 0 0 z Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds, by governmental authorities as follows: December 31.2002 2001 (in thousands) % Rate Due Industrial Development Authority of Russell county, Virginia: Junior debentures outstanding were as follows: December 31.2002 2001 (in thousands) 8-1/4% Series A due 2026 September 30 8% Series B due 2027-March 31 unamortized Discount Total S -S 75,000 90,000 (3 .493)U161, 50 7.70 2007 -November 1 S 17, 500 5.00 2021 -November 1 19,500 Putnam County, West Virginia: S 17, 500 19, 500 At December 31, 2002, future annual long-term debt payments are as follows: 5.45 2019 -June 1 41 6.60 2019 -July 1 3 Mason County, West Virginia: 7-7/8 2013 -November 1 1 6.85 2022 -June 1 4 6.60 2022 -October 1 5 6.05 2024 -December 1 3 unamortized Discount Total 0,000 40,000 0,000 30,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 155,007 121,008 530,010 100,011 217,513 782. 216 1,905,765 (11,904)0,000 0,000 0,000 0,000 1. 973)10,000 40,000 50,000 30,000 (2 096)1234.90A E-1 1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to APCO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to APCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investments Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note Note Note Note Note Note Note 17 18 20 22 23 24 29 E-1 2 INDEPENDENTAAUDITORS REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian PowerCompanyand subsidiaries as of December31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance aboutwhetherthe financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 E-1 3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable to common Stock$1,400,160 1180T3 81 219,779 15,263 53. 869 181,173 181,173$1,350,319 1.098.142 252,177 7,738 68.015 191,900 (30.024)161,876$1,304,409 1.108.532 195,877 5,153 80,828 120,202 (25. 236)94,966$1,190,997 968.207 222,790 2,709 75. 229 150,270 150,270 2.131$18 139$1,187,745 975, 534 212,211 (1,343)77.824 133,044 133,044 2.131£ 410Q9f 1.095$ 160.781£__1798JA1 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$3,467,626 1.465.174£2_Q02 ,452$Z,153,240 $3,354,320 1.377.032$1,977,288 3$Z.2 "388$3,266,794 1.299.697$3,151,619 1.210.994£1,40,625$ &08Q8123$3,053,565 1.134. 348$1,912,=21 _$13 X&ZL42i Common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$ 616,410 (59,357)290.611$_847 7 604$ 615,395 176.103=$ 191 9,AH$ 614,380 99.069$ 713,449$ 613,899 246, 584$860.,483$ 613,518 186.441$Z 79R9,9 cumulative Preferred stock -subject to Mandatory Redemption (a)Long-term Debt (a)Obligations under Capital Leases (a)Total Capitalization and Liabilities L$ L6 1 Q6Z R 2$ i_ 4 Q$L 72293&$ 252i0f$L 25,000$ _ 9 2 4 .5 4 5 L Z &S 4_0ZZ0 L A42L3Z$3,87,491 (a) Including portion due within one year.F-1 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Manaaement s Narrative Analysis of Results of ODerations Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 689,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. CSPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each companies percentage share of AEP Power Pool revenues and costs.Results of Operations Net Income increased $19 million or 12% in 2002 due to reduced interest charges and a$30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio excise taxes stranded by Ohio deregulation offset by higher operating expenses.Operating Revenues Operating Revenues increased in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were: Increase (Decrease) From Previous Year (dollars in millions)Amount %Retail* S51 8 wholesale Marketing 3 2 unrealized MTM (4) (22)Other 1 3 wholesale Electricity* 51 6 Energy Delivery* 9 2 Sales to AEP Affiliates (10) (15)Total Revenues $5Q 4* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 35%. For the fall season, heating degree days increased 34%. This reflects a return to more normal weather conditions since the weather experienced in 2001 was abnormally mild.Operating Expenses Operating Expenses increased in 2002 mainly as a result of purchased power, operating expenses and state taxes.Changes in the components of Operating Expenses were: Increase (Decrease) From Previous Year (dollars in millions)Amount X Fuel wholesale Purchased Power AEP Affiliates Purchased Power other operation Expenses Maintenance Expense Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total$10 4 18 18 (2)4 25 5 6 37 6 8 (4)3 22 5 7 10%by a coal Fuel cost increased as a result of a increase in generation partially offset slight cost decrease per ton of consumed.Wholesale Purchased Power increased in 2002 due to increased purchases from third F-2 parties for resale to wholesale customers and to meet internal demand.Expenses related to AEP Affiliates Purchased Power increased due to greater system pool capacity charges.The increase in Other Operation expenses was attributable to a number of factors: higher OPEB post retirement costs as a result of higher medical cost and lower investment performance, 2002 Sustained Earnings Initiative Expenses, and the 2001 reversal of a quality of service liability accrual. The increase was partially offset by a reduction in energy trading overheads reflecting reduced marketing activity.The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in property taxes and a full year of the state excise tax which replaced the state gross receipts tax during 2001.The increase in Income Taxes is predominately due to an increase in state taxes as a result of the State of Ohio s tax legislation resulting from utility deregulation. This increase was offset in part by a decrease in federal taxes due to a decrease in pre-tax operating income.Nonoperating Income and Nonoperating Expense The decrease in Nonoperating Income in 2002 is due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System s traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. CSPCo s share of the AEP Power Pool s gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in Nonoperating Income. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand.The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy trading incentive compensation. Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax nonoperating income.Interest Charges Interest Charges decreased in 2002 primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.F-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income 2002 Year Ended December 31.2001 (in thousands) 2000 OPERATING REVENUES: wholesale Electricity Energy Delivery sales to AEP Affiliates Total operating Revenues OPERATING EXPENSES: Fuel Purchased Power: Wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME S 850,680 492,278 57,202 1.400.160 185,086 15,023 310,605 237,802 60,003 131,624 136,024 104.214 1,180.381 219,779 26,360 S 799,589 483,219 67,511 1,350.319 175,153 10,957 292,199 219,497 62,454 127,364 111,481 99.037 1 098.142 252,177 32,756 21,095 3,923 68,015 191,900 (30.024)161,876 1.095$ 856,998 398,046 49. 365 1,304.409 189,155 9,879 287,750 219,840 69,676 99,640 123,223 109, 369 1.108, 532 195,877 20,580 8,070 7,357 80.828 120,202 (25, 236)94,966 1.783$ ~93,13 NONOPERATING EXPENSES 4,308 NONOPERATING INCOME TAX EXPENSE INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 6,789 53 869 181,173 181,173 1.332$ 179, 841 Consolidated Statements of Comprehensive Income 21 Year Ended December 31.'02 2001 2000 (in thousands) 1,173 $161,876 $94,966 NET INCOME 18: OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability (M COMPREHENSIVE INCOME $12 The common stock of the CSPCo is who7ly owned by AEP.See Notes to Financial Statements beginning on page L-1.(267)9. 090)3261,B 6 594--9-U F-4 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eaminqs Year Ended December 31.2002 2001 2000 (in thousands) Retained Earnings January 1 Net Income Deductions: cash Dividends Declared: Common Stock Cumulative Preferred Stock Total cash Dividends capital stock Expense Total Deductions Retained Earnings December 31$176,103 181,173 357,276 7% series Declared 65,300 350 65,650 1.015 66.665$290,611.$ 99,069 161.876 260.945 82,952 875 83,827 1.015 84.842$i176,13$246,584 94.966 341.550 240,600 1.400 242,000 481 242.481 SL32Pa9 see Notes to Financial Statements beginning on page L-1.F-5 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation $1,582,627 413,286 1,208,255 165,025 98.433 3,467,626 1.465,174 NET ELECTRIC UTILITY PLANT 2,002X452 OTHER PROPERTY AND INVESTMENTS 35.759 LONG-TERM ENERGY TRADING CONTRACTS 77.810$1,574,506 401,405 1,159,105 146,732 72.572 3,354,320 1,377.032 1,977.288 40.369 73. 310 12,358 41,770 63,470 16,968 (745)20,019 38,984 7,087 84,323 28.733 312.967 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Energy Trading Contracts Prepayments and other Current Assets TOTAL CURRENT ASSETS 1,479 31,257 49,566 54,518 22,005 (634)24,844 40,339 12,671 63,348 7.308 306.701 REGULATORY ASSETS 257.682 DEFERRED CHARGES 72,836$2,753,240 262.267 56,187$2,722,388 TOTAL ASSETS see Notes to Financia7 Statements beginning on page L-1.F-6 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock No Par value: Authorized 24,000,000 shares outstanding 16,410,426 shares Paid-in capital Accumulated other comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity cumulative Preferred stock subject to Mandatory Redemption Long-term Debt -General Long term Debt Affiliated companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year General Long-term Debt Due within One Year Affiliated Companies short-term Debt Affiliated Companies Advances from Affiliates Accounts Payable General Accounts Payable Affiliated companies Taxes Accrued Interest Accrued Energy Trading Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 41,026 575,384 (59,357)290.611 847,664 418,626 160,000 1,426.290 95,460 43,000 290,000 89,736 81,599 112,172 9,798 46,375 36,790 709.470 437.771 33.907 29.926 20.416$Za53 24Q$ 41,026 574,369 176,103 791,498 10,000 571,348 1.372.846 36,715S 20,500 200,000 181, 384 60,689 83,697 116,364 10,907 72,082 36, 305 781,928 443, 722 37.176 37.101 12.900£tZ722 za83 F-7 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark to Market of Energy Trading Contracts Extraordinary Loss Change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities S 181,173 131,753 23,292 (3,269)(16,667)(3,992)(6,180)(5,584)26,949 (8,027)(22,448)297,000$ 161,876 128,500 24,108 (4,058)(44,680)30,024 19,987 (7,780)2,551 (16,249)(42,066)(18,769)233,444 S 94,966 100,182 (4,063)(3,482)5,352 (3,393)25,236 (29,737)11,957 38,479 81,284 39,483 (121,115)132.44 367,590 INVESTING ACTIVITIES: Construction Expenditures Proceeds From Sales and Leaseback Transactions and other Net cash Flows used For Investing Activities FINANCING ACTIVITIES: change in Advances from Affiliates (net)Issuance of Affiliated Long-term Debt Retirement of Preferred Stock Retirement of General Long-term Debt Retirement of Affiliated Long-term Debt Change in short-term Debt (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows used For Financing Activities (136,800) (132,532)730 (136,070)(212,641)160,000 (10,000)(133,343)(200,000)290,000 (65,300)(525)(171 809)10.84 (121.691)92,652 200,000 (5,000)(314,733)(82,952)(962)(110.995)(127,987)1. 560 (126.427)88,732 (10,000)(25,274)(45,500)(240,600)(1.575)(234,217)Net Increase (Decrease) in cash and cash Cash and cash Equivalents January 1 cash and Cash Equivalents December 31 Equivalents (10,879)12.358 3-1"79 758 11,600 S-1 3-5-8 6,946 4.654 S-II&M0 supplemental Disclosure: cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000 and$68,506,000 and for income taxes was $117,591,000, 80,485,000 and $81,109,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were S1,o09,000 and $10,777,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.F-8 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of CaDitalization December 31.2002 2001 (in thousands) COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:. S100 par value authorized shares 2,500,000 525 par value -authorized shares 7,000,000$ 847.664 S 791.493 series Number of shares Redeemed Year Ended December 31, 2002 2001 2000 shares outstanding December 31, 2002 Subject to Mandatory Redemption: 7.00% 100,000 50,000 100,000 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior unsecured Notes Notes Affiliated Junior Debentures Less Portion Due within one Year Total Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION 222,797 91,275 147,554 160,000 ( 43.000)578.626 S1L 42,9 243,197 91,220 147,458 200,000 109,973 (220. 500)571. 348 1S1,7-21, A-C see Notes to Financial statements beginning on page L-1.F-9 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) December 31.2002 2001 (in thousands) % Rate Due 7.25 2002 7.15 2002 6.80 2003 6.60 2003 6.10 2003 6.55 2004 6.75 2004 8.70 2022 8.55 2022 8.40 2022 8.40 2022 7.90 2023 7.75 2023 7.60 2024 unamortized Total October 1 S -November 1 May 1 13,000-August 1 25,000 November 1 5,000 March 1 26,500 May 1 26,000 July 1 2,000 August 1 15,000 August 15 14,000 October 15 13,000 May 1 40,000 August 1 33,000 May 1 11,000 Discount (703)$ 14,000 6,500 13,000 25,000 5,000 26, 500 26,000 2,000 15,000 14,000 13,000 40,000 33,000 11,000 (803)% Rate Due 6.85 2005 6.51 2008 6.55 2008 unamortized Total October 3 $ 36,000 February 1 52,000 June 26 60,000 Discount (446)S 36,000 52,000 60,000 (542)Notes payable to parent company were as follows: December 31, 2002 2001 (in thousands) % Rate (a)6.501%Total Due 2002 -Sept 25 S -2006 May 15 160.000 S 160,00$200,000 First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: December 31, 2002 2001 (in thousands)(a) Redemed 9/25/02 Junior debentures outstanding were as follows: December 31, 2002 2001 (in thousands) % Rate Due 8-3/8 2025 7.92 2027 unamortized Total Sept 30 S -March 31 -Discount -5~S 72,843 40,000 (2.870)At December 31, 2002, future annual long-term debt payments are as follows:% Rate Due 6-3/8 2020 -December 1 $48,550 6-1/4 2020 -December 1 43,695 unamortized Discount (970)Total 191,m$48,550 43,695 (1.02 5)2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 43,000 52,500 36,000 160,000 332.245 623,745 (2.119)5621 Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant.F-1 0 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to CSPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CSPCo.The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer Choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Jointly owned Electric Utility Plant -Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 28 Note 29 F-1 I INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31,2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December31, 2002 in conformitywith accounting principles generally accepted in the United States of America.Is! Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 F-1 2 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY Selected Consolidated Financial Data AND SUBSIDIARIES Yea 2002 INCOME STATEMENTS DATA: Operating Revenues operating Expenses operating Income (Loss)Nonoperating Items, Net Interest charges Net Income (Loss)Preferred stock Dividend Requirements Earnings (Loss)Applicable to Common stock$1,526,764 1.375,575 151, 189 16,726 93.923 73,992 4.601 2001$1, 526,997 1.367,292 159,705 9,730 93. 647 75,788 ir Ended December 31.2000 1999 (in thousands) $1,488,209 1.522.911$1,351,666 1.243,014 (34,702) 108,652 1998$1,405,794 1,239,787 166,007 (839)68.540 96,628 4.824 9,933 107. 263 (132,032)4,530 80.406 32,776 4.621 4,885$ 71,167$ 27,891 2002 2001 December 31, 2000 (in thousands) _ _ _ _1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$5,029,958 2,568.604$2,.461,3~54 i48L28719$4,923,721 2.436.972$2,486, 749$4,871,473
- 2. 280.521$2.,590.,952
$4,770,027 2.194.397$2,5575,30 $4,631,848 2.081, 355$2.,550.,493 Total Assets common stock and Paid-in capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity cumulative Preferred stock: Not subject to Mandatory Redemption subject to Mandatory Redemption (a)Total Cumulative Preferred stock$ 915,144 (40,487)143.996$ 789,800 (3,835)74,605$ 789,656 3,443$ 789,323 166.389$ 789,189 2 53.154$108,11 $ 8,36 S 793,099 6 $ 9,552, $1 273 S 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 64.945$163,046$1, 617,062 64, 945 11,652-Q&Z 64,945$1,388,939 64.945$£ 74.193$1,324, 3-26 68.445$ 7-7.718 Long-term Debt (a)obligations under capital Leases (a)$ 50,848$ 61L933$-163,173$ 187,965$ 186,427 Total capitalization And Liabilities A 58L7191 4. 394 062$5,774 108$4,575,210 (a) Including portion due within one year.G-1 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 571,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs.maintenance costs incurred as part of planned and unplanned outages at Cook Plant and Rockport Plant.During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection (see Note 5).As a result of costs incurred in 2000 to restart the Cook Plant and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, Net Income increased in 2001 by $208 million. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including l&M, in a suit over deductibility of interest claimed in AEP s consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. The deferrals were expensed and impacted Net Income in 2000.Operatina Revenues Increase Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo s Rockport Plant capacity to KPCo through 2004. The KPCo agreement extends until December 31, 2009 for Rockport Unit I and until December 7, 2022 for Rockport Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. Therefore, l&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.Results of Operations During 2002 Net Income decreased by $2 million due to increased operations and Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase reflects increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in Operating Revenues: Increase (Decrease) From Previous Year (dollars in milions)2002 2001 Amount % Amount %Retail* $ 28.2 Marketing
2.6 other
2.6 Total wholesale Electricity 33.4 Energy Dellvery*
7.3 sales
to AEP Affiliates (40 Total 4 1 6 S (2.3)(12.0)5 .0 N.M (4)13 3 (9.3) (1)2 3.4 1) (16) 44.7) N.M. 3.3 21 3 N.M. = Not Meaningful
- Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.G-2 The increase in Operating Revenues in 2001 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power l&M could sell to its affiliates in the AEP Power Pool.Operating Expenses Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000. The changes in the components of Operating Expenses were: Plant nuclear units for restart with their return to service in 2000. Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002.The increase in Depreciation and Amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of l&M s share of deferred merger costs.Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment of amounts recorded in December 2000 to actual expenses.Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income. The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income.Increase (Decrease)
From Previous Year (dollars in millions)2002 2001 Fuel I wholesale Electricity Purchases AEP Affiliate Purchases Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total I Amount % Amount %'0(10.6) (4) $ 39.2 19 4.7 25 4.9 36 (4.5)13.6 24.3 3.8 (7.8)(15.2)w--(2)3 19 (27.2) (10)(147.7) (25)(92.6) (42)2 9.3 6 (12) 4.9 8 (28) 53.6 N.M.1 ) (10)Nonoperating Income.Expenses and Income Taxes Nonoperating N.M. = Not Meaningful Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs.The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21 %.Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. The decrease in Other Operation and Maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP s traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP s traditional marketing area.Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders incentive compensation. Nonoperating Expenses increased in 2001 due to increased trading overheads and traders incentive compensation. The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income.Interest Charges The decrease in 2001 Interest Charges reflects the recognition in 2000 of deferred G-3 interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998. G-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31.2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME (LOSS)NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES NET INCOME (LOSS)PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$ 990,905 321,721 214,138 1. 526. 764 239,455 23,443 233,724 462,707 151,602 168,070 57,721 38. 853 1. 375. 575 151,189 93,739 71,029 5,984 93. 923 73,992 4.601$ 957,548 314,410 255.039 1,526.997 250,098 18,707 238,237 449,115 127,263 164,230 65,518 54.124 1. 367,292 159,705 97,810 83,037 5,043 93 647 75,788 4.621 S 71,167$ 966,882 311,019 210.308 1.488.209 210,870 13,785 265,475 596,861 219,854 154,920 60,622 524 1.522.911 (34,702)76,499 62,377 4,189 107.263 (132,032)4,624$ 315,2656)Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME (LOSS) $ 73,992 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 3,835 Cash Flow Power Hedge (286)Minimum Pension Liability (40,201)COMPREHENSIVE INCOME (LOSS) $ 37, see Notes to Financia7 statements beginning on page L-1.$75,788 $(132,032) (3,835)-Z2 5113Z-02)G-5 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings 2002 Year Ended December 31.2001 (in thousands) 2000 Retained Earnings January 1 Net Income (Loss)Deductions: cash Dividends Declared: Common stock cumulative Preferred stock: 4-1/8% series 4.56% Series 4.12% series 5.90% series 6-1/4% series 6.30% series 6-7/8% series Total Cash Dividends Declared capital stock Expense Total Deductions $ 74,605 73, 992 148, 597 S 3,443 75.788-79.231$ 166,389 (132.032)34. 357 229 66 52 897 1,203 834 1.186 4,467 134 4.601 229 66 72 897 1,203 834 1.186 4,487 139 4.626 26,290 230 66 74 897 1,203 834 1,186 30,780 134 30.914 Retained Earnings December 31 $143 See Notes to Financia7 statements beginning on page L-1.S 74,6L05$3 1 A443 G-6 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 (in thousand 2001 S)ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General (including nuclear fuel)Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$2,768,463 971,599 921,835 220,137 147.924 5,029,958 2.568,604 2.461. 354$2,758,160 957,336 900,921 233,005 74.299 4,923,721 2,436.972 2.486.749 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870.754 834,109 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83, 265 OTHER PROPERTY AND INVESTMENTS 120,941 CURRENT ASSETS: cash and cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading and Derivative Contracts Accrued Utility Revenues Prepayments and other TOTAL CURRENT ASSETS 3,237 191,226 67,333 122,489 30,468 (578)32,731 95,552 68,148 6,511 11,899 629.016 127.977 16,804 46,309 60,864 31,908 25,398 (741)28,989 91,440 108,895 2,072 6.497 418.435 REGULATORY ASSETS 348.212 408,927 DEFERRED CHARGES 73.649 34,967 TOTAL ASSETS$4,58,191 see Notes to Financia7 Statements beginning on page L-1.G-7 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: common Stock -No Par value: Authorized -2,500,000 shares outstanding -1,400,000 Shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity cumulative Preferred Stock: Not subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION $ 56,584 858,560 (40,487)143 996 1,018,653 8,101 64,945 1.587,062 2,678, 761 620,672 138.965 759.637$ 56,584 733,216 (3,835)74.605 860,570 8,736 64,945 1. 3123082 2.246. 333 600,244 87,025 687,269 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning other TOTAL OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within one Year Accounts Payable General Accounts Payable -Affiliated Companies Taxes Accrued Interest Accrued obligations under capital Leases Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES 30,000 125,048 93,608 71,559 21,481 8,229 48,568 92. 822 491,315 340,000 86,766 43,956 69,761 20,691 10,840 93,413 76 486 741.913 DEFERRED INCOME TAXES 356,197 400,531 DEFERRED INVESTMENT TAX CREDITS 97,709 105,449 DEFERRED GAIN ON SALE AND LEASEBACK -ROCKPORT PLANT UNIT 2 73,885 77, 592 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32, 261 42,936 92,039 REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES $4 58iLL191.$4,3940Q6Z See Notes to Financia7 Statements beginning on page L-1.G-8 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of cash Flows Year Ended December 31.2002 2001 (in thousands) 2000 OPERATING ACTIVITIES: Net Income (Loss)Adjustments for Noncash Items: Depreciation and Amortization Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net)Amortization of Nuclear Outage Costs Deferred Income Taxes Deferred Investment Tax credits Unrecovered Fuel and Purchased Power Costs Changes in Certain Current Assets And Liabilities: Accounts Receivable (net)Fuel, Materials and Supplies Accrued utility Revenues Accounts Payable Taxes Accrued Mark-to-Market of Energy Trading and Derivatives Contracts Disputed Tax and Interest Related to COLI Regulatory Asset Trading Losses Regulatory Liability Trading Gains change in other Assets Change in other Liabilities Net cash Flows From Operating Activities $ 73,992 168,070 (26,577)40,000 (16,921)(7,740)37,501 (102,283)(7,854)(4,439)87,934 1,798 (9,517)(992)2,494 (28,233)21.001 228.234$ 75,788 166,360 418 40,000 (29,205)(8,324)37,501 64,841 (19,426)(2,072)(60,185)1,345 (62,647)8,493 34,293 (5,871)(5,102)236,207$ (132,032)163,391 5,737 40,000 (125,179)(7,854)37,501 (25,305)10,743 44,428 85,056 19,446 14,830 56,856 (17,914)(7,416)(68,160)37.309 131.437 INVESTING ACTIVITIES: Construction Expenditures Bu yout of Nuclear Fuel Leases Other Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES: capital Contributions from Parent Company Issuance of Long-term Debt Retirement of cumulative Preferred Stock Retirement of Long-term Debt change in Advances from Affiliates (net)change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and Cash Equivalents January 1 cash and cash Equivalents December 31 (167,484)1. 759 (165 .72 5)125,000 288,732 (424)(340,000)(144,917)(4.467)(76.076)(91,052)(92,616)1,074 (182.594)297,656 (44,922)(299,891)(4.487)(51.644)(171,071)587 (170.484)199,220 (314)(148,000)253, 582 (224,262)(26,290)(3. 368).50. 568 (13,567)16.804 1,969 11,521 14.835 3,314 l_6104 S 14, 835 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000 and$82,511,000 and for income taxes was $60,523,000, $100,470,000 and $73,254,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,023,000 and$22,218,000 in 2001 and 2000, respectively. see Notes to Financial Statements beginning on page L-1.G-9 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) $1.018.653 S 860.570 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK:$100 Par value -Authorized 2,250,000 shares$25 Par value -Authorized 11,200,000 shares call Price December 31, Number of shares Redeemed Series 2002 (a) Year Ended December 31.2002 2001 2000 Not Subject to Mandatory Redemption-$100 Par: 4-1/8% 106.125 20 -3,750 4.56% 102 ---4.12% 102.728 6,326 -1,375 Subject to Mandatory Redemption-S100 Par(b): 5.90% (c) ---6-1/4% (c) ---6.30% (c) ---6-7/8% (d) ---shares outstanding December 31. 2002 55,369 14,412 11,230 152,000 192,500 132,450 172,500 5,537 1,441 1. 123 8.101 15,200 19,250 13,245 17.250 64.945 5,539 1,441 i1. 756 8.736 15,200 19, 250 13,245 174 950 64.945 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 174,245 264,141 Installment Purchase Contracts 310,336 310,239 senior unsecured Notes 747,027 696,144 other Lon -term Debt (e) 223,736 219,947 Junior Debentures 161,718 161,611 Less Portion Due within one Year (30.000) (340.000)Long-term Debt Excluding Portion Due within one Year 1.587,062 1.312,082 TOTAL CAPITALIZATION 4S2j1 SZ,2A33 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends (b) sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of these due dates. Shares previously purchased may be applied to meet the sinking fund requirement. cc) commencing in 2004 and continuing through 2008 I&M may redeem at $100 per share, 20,000 shares of the 5.90%series, 15,000 shares of the 6-1/4% series and 17,500 shares of? the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. The series are callable beginning November 1, 2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March 1, 2004 for the 6.30% series at $100 plus accrued dividends.(d) commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. callable at $100 per share plus accrued dividends beginning February 1, 2003.(e) Represents a liability for SNF disposal including interest payable to the DOE. See Note 9.See Notes to Financial Statements beginning on page L-1.G-10 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Lonq-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 7.60 2002 7.70 2002 6.10 2003 8.50 2022 7.35 2023 7.20 2024 7.50 2024 unamortized November 1 December 1-November 1-December 1 October 1 February 1 March 1 Discount.S 30,000 5 75,000 15,000 30,000 25.000 (75 5)$ 50,000 40,000 30,000 75,000 15,000 30,000 25,000 (859)The terms of* the installment purchase contracts require l&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date).Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) December 31.2002 2001 (in thousands) % Rate Due (a) 2002 6-7/8 2004 6.125 2006 6.45 2008 6.375 2012 6 2032 unamortized September 3 S -3uqy 1 150,000 December 15 300,000 November 10 50,000 November 1 100,000 December 31 150,000 Discount (2.973)S7AL 02$200,000 150,000 300,000 50,000 (3.856)% Rate Due City of Lawrenceburg, Indiana: 7.00 2015 April 1 S 25,000 5.90 2019 -November 1 52,000 city of Rockport, Indiana: (a) 2014 August 1 7.60 2016 March 1 6.55 2025 June 1 (b) 2025 June 1 4.90(c) 2025 June 1 city of Sullivan, Indiana: 5.95 2009 May 1 unamortized Discount I1 S 25,000 52,000 50,000 40,000 50,000 50,000 (a) A floating interest rate was determined quarterly. The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.Junior debentures outstanding were as follows: December 31.2002 2001-in thousands) 40,000 50,000 50,000 50,000% Rate Due 8.00 2026 7.60 2038 unamortized Total March 31 S 40,000 June 30 125,000 Discount (3 282)S161 71 S 40,000 125,000 (3.389)45,000 45,000 (1.664) (1 761)t3036 S1 3 (a) A variable interest rate was determined weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001.(b) In June 2001 an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for 2002 ranged from 1.3% to 1.7% and averaged 1.5%. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9%to 4.9% in 2001 and averaged 3.3% during 2001.(c) Rate is fixed until June 1, 2007 (term rate bonds).Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.At December 31, 2002, future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 30,000 150,000 300,000 50,000 1.095.736 1,625,736 (8.674)51 617 06 G-1 I INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to combined Notes to Consolidated Financial statements The notes to I&M s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1.significant Accounting Policies Merger Nuclear Plant Restart Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Asset Impairments and Investment Value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and Sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 5 Note 7 Note 8 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 G-12 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America./sI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 G-13 KENTUCKY POWER COMPANY KENTUCKY POWER COMPANY Selected Financial Data Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 INCOME STATEMENTS DATA: Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Net Income$ 378,683 336.486 42,197 5,206 26.836$ 20,567$ 379,025 331. 347 47,678 1,248 27. 361$ 21,565$ 389,875 340.137 49,738 2,070 31.045 20,76i3$ 358,757 304.082 54,675 (327)28.918$ 2iA3A0$ 362,999 311.106 51,893 (1,726)28.491 kS _21,676 Year Ended December 31.2002 2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common Stock and Paid-in Capital Accumulated Other comprehensive Income (LoSS)Retained Earnings Total Common shareholder's Equity$1,295,619 397, 304$1,164,676 $ 259,200 (9,451)48.269$1,128,415 384.104$ 744,311 S 999,048$ 209,200 (1,903)$1,103,064 360.648 S 742,416$1,494,543 $ 209,200 57.513 S_266,713$1,079,048 340.008$ 739.040$ 986.123$ 209,200 67.110$ 2 6,310$1,043,711 315. 546$ 728 165$ 921,3A7$ 199,200 71.,452 Si248 0-18 Lon -term Debt (a)Debt ( )3 963632$ 346-093 5-365.,782 L_3 68-838 obligations Under Capital Leases(a)Total Capitalization and Liabilities I1164. 676$1,494,543 $921,84 (a) Inc7uding portion due within one year.H-1 KENTUCKY POWER COMPANY Management s Narrative Analysis of Results of Operations KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. KPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs.KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP s settlement restructuring agreement filed with the FERC becomes operative. The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Underthe unit power agreement, there is a demand charge for the right to receive the power, which is payable even it the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity.Results of Operations Net Income for 2002 decreased $1 million or 5%.Total Revenues were flat while increases in Operating Expenses, driven by expenses related to planned outages at the Big Sandy plant, were offset by comparable gains in net nonoperating income which benefited from decreases in trading incentive compensation. Changes in Revenues wholesale Electricity* Energy Delivery*Sales to AEP Affiliates Total Increase (Decrease) Year-to-Date (dollars in milions Amount %$13 6 j!) C(34)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Revenues in 2002 were comparable to those of last year. Increased sales to retail electricity customers reflecting warmer summer weather, colder days in late 2002, and increased fuel recovery revenues were offset by lower Sales to AEP Affiliates resulting from planned outages in 2002. KPCo s decreased generation was due to scheduled maintenance resulting in lower availability in the fourth quarter.Changes in Operating Expenses Increase (Decrease) Year-to-Date (dollars in millions)Amount %S(5.6) (8)-N.M.Fuel wholesale Electricity Purchases from AEP Affiliates other operation Maintenance Depreciation Taxes other Than Income Taxes Income Taxes Total Operating Expenses N.M. = Not Meaningful 2.8 (5.4)12.6.7.4-E4)2 (9)56 2 5 (4)2 Fuel expense decreased in 2002 as a result of planned fourth quarter outages at the Big Sandy H-2 plant for scheduled boiler maintenance. The 800 megawatt Unit 2, representing approximately 75%of the plants generation capacity, was off-line from mid-September through the end of the year, thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to meet demand during the planned outages at the Big Sandy plant.Other Operation expense decreased in 2002 due to reduced consumption of emission allowances due to the planned outage; reduced accruals for trading incentive compensation due to reduced trading activity; and improvements in transmission expense resulting from less wholesale activity and related transmission, and an increase in AEP transmission equalization credits. Underthe AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company s peak demand and investment. A decrease in KPCo s peak demand relative to its affiliates peak demand was the main reason for the increase in transmission equalization credits. These developments were offset in part by severance expenses related to a sustained earnings initiative (see Note 11).Nonoperating Income Taxes for 2002 have increased as a result of increases in pre-tax income for the year offset in part by prior-year tax return adjustments. Other Changes Nonoperating Income for 2002 decreased as a result of AEP s previously announced plan to reduce trading activity, and decreased margins on power trading activity outside of the AEP System s traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased in 2002 as a result of decreases in trading incentive compensation. Maintenance expense increased in 2002 primarily as a result of planned power plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for planned boiler overhaul and electric plant maintenance. The Company experienced marginal increases in overhead line maintenance expense.H-3 --KENTUCKY POWER COMPANY Statements of Income Year 2002 (in Ended December 31.2001 2000 thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES$218,665 132,054 27,964 378.683 65,043 29 133,002 52,892 35,089 33,233 8,240 8.958 336,486 42,197 7,863 753 1,904 26,836 20.567$205,476 131,183 42. 366 379.02 5 70,635 86 130,204 58,275 22,444 32,491 7,854 9. 358 331, 347 47,678 10,881 8,949 684 27. 361 La25=U6$226,708 121,346 41.821 389,875 74,638 1,940 127,707 52,495 25,866 31,028 7,251 19,212 340.137 49,738 6,139 2,940 1,129 31.045 L 20,76 NET INCOME Statements of Comprehensive Income 2002 NET INCOME $ 20,5b7 OTHER COMPREHENSIVE INCOME (LOSS)Cash Flow Interest Rate Hedge 2,225 Minimum Pension Liability (9.773)COMPREHENSIVE INCOME $1 3, ol Statements of Retained Earnings 2002 RETAINED EARNINGS JANUARY 1 $48,833 NET INCOME 20,567 CASH DIVIDENDS DECLARED 21,131 RETAINED EARNINGS DECEMBER 31 See Notes to Financial statements beginning on page L-1.Year Ended December 31, 2001 2000 (in thousands) $21,565 $20,763 (1,903)Year Ended December 31.2001 (in thousands) $57,513 21,565 30.245$A&2000$67,110 20,763 30.360 H4 KENTUCKY POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and supplies Accrued Utility Revenues Accrued Tax Benefit Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financial statements beginning on page L-1.$ 275,121 373,639 425,817 55,913 165.129 1,295,619 397.304 898.315 6.904 29.871 2,304 22,044 23,802 2,889 (192)10,817 16,127 5,301 1,253 24,320 2,127 110,792 101,976 16.818$1,164,676 S 271,070 374,116 402,537 65,059 15.633 1,128,415 384.104 744.311 6,492 29.477 1,947 20,036 16,012 3,333 (264)12,060 15,766 5,395 33,905 1,314 109,504 97.692 11,572 SL999,048 H-5 KENTUCKY POWER COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock $50 Par value: Authorized 2,000,000 shares outstanding 1,009,000 shares Paid-in Capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareowner S Equity Long-term Debt Long-term Debt Affiliated Companies TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year -General Long- term Debt Due within one Year -Affiliated Companies Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial statements beginning on page L-1.S 50,450 208,750 (9,451)48.269 298,018 391,632 60.000 749,650 27. 319 15,000 23,386 46,515 44,035 8,048 6,471 17,803 14. 322 175. 580 178,313 9,165 11.488 13.161$ 50,450 158,750 (1,903)48.833 256,130 176,093 75,000 507. 223 11.929 95,000 66,200 23,464 22,557 4,461 10,305 5,269 38,664 12,882 278,802 168,304 10,405 14,917 7,468 S1,164,676 H-6 KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Mark-to-Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Disputed Tax and Interest Related to COLI Change in other Assets change in other Liabilities Net cash Flows From Operating Activities $ 20,567 33,233 9,839 (1,240)2,998 (12,267)(9,426)882 94 44,529 (11,558)(21,491)16.161 72, 321$ 21,565 $ 20,763 32,491 6,293 (1,251)(4,707)(1,454)23,694 (7,658)1,105 (22,942)(1,580)(2,762)(9,446)33, 348 31,034 3,765 (1,252)2,948 (4,376)(20,930)8,386 7,237 39,883 2,025.5,943 62,653 (62. 702)95, 377 INVESTING ACTIVITIES: construction Expenditures Proceeds From Sales of Property Net Cash Flows Used For Activities Investing (178,700)217 (178,483)(37,206)216 (36 990)(36,209)266 (35.943)FINANCING ACTIVITIES: capital contributions from Parent Company Issuance of Long-term Debt Retirement of Long-term Debt change in short-term Debt (net)change in Advances From Affiliates (net)Dividends Paid Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 50,000 274,964 (154, 500)(42,814)(21.131)106,519 357 1$947 3-2.3-04 75,000 (60,000)18,564 (30,245)3, 319 (323)2,270$ 1,947 69,685 (105,000)(39,665)47,636 (30 ,360)(57.704)1,730 540-2,270 supplemental Disclosure: Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000 and$28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $22,021, $817,000 and$2,817,000 and in 2002, 2001 and 2000, respectively. see Notes to Financial Statements beginning on page L-1.H-7 KENTUCKY POWER COMPANY Statements of Capitalization December 31, 2002 2001 (in thousands) $298.018 $256.130 COMMON SHAREHOLDER S EQUITY LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Senior unsecured Notes Notes Payable Junior Debentures Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financia7 statements beginning on page L-1.352,508 75,000 39,124 (15.000)451.632$7A9,6iQ 59,383 147,625 100,000 39,085 (95.000)251.093 5507.2_2 H-8 KENTUCKY POWER COMPANY Schedule of Lonq-term Debt First mortgage bonds follows: outstanding were as December 31.2002 2001 (in thousands) % Rate Due 6.65 2003 6.70 2003 6.70 2003 7.90 2023 Unamortized Notes payable to banks outstanding were as follows: December 31.2002 2001 (in thousands) X Rate Due 7.45 2002 September 20 S -=Junior debentures outstanding were as follows: May 1 June 1 July 1 June 1 Discount S S 15,000 15,000 15,000 14,500 il 17)First mortgage bonds were secured by a first mortgage lien on electric utility plant.Senior unsecured notes outstanding were as follows: December 31, 2002 2001 (in thousands) % Rate Due 8.72 2025 June 30 unamortized Discount Total 540,000 (876)539,12$40,000 (915)539 08% Rate Due (a) 2002 6.91 2007 6.45 2008 5.50 2007 4.31 2007 4.37 2007 unamortized December 31.2002 2001 (in thousands) -November 19 S -S 70,000 October 1 48,000 48,000 November 10 30,000 30,000 July 125,000 -November 12 80,400 -December 12 69,564 -Discount (456) (375)S3258S4,Z Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.At December 31, 2002, future annual long-term debt payments are as follows: (a) A floating interest rate is determined monthly. The rate December 31, 2001 was 4.3%.Notes payable to parent company were as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 15,000 60,000 322,964 70.000 467,964 (1.332)S466,-632% Rate Due 4.336 2003 6.501 2006 December 31.2002 2001 (in thousands) $15,000 S15,000 60.000 60.000 S75,00 57,0 May 15 May 15 H-9 KENTUCKY POWER COMPANY Index to combined Notes to Financial statements The notes to KPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1.Significant Accounting Policies Merger Rate Matters Effects of Regulation Commitments and Contingencies Guarantees Sustained Earnings Improvement Initiative Asset Impairments and Investment value Losses Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 4 Note 6 Note 7 Note 9 Note 10 Note 11 Note 13 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 29 H-10 INDEPENDENT AUDITORS REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 H-I 1 OHIO POWER COMPANY OHIO POWER COMPANY Selected Financial Data 2002 Year Ended December 3 2001 2000 (in thousands) .INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred Stock Dividend Requirements Earnings Applicable To Common stock$2,113,125 1.814,796 298,329 5,376 83. 682 220,023 220,023 1.258$2,098,105 1.857, 395 240,710 18,686 93.603 165,793 (18. 348)147,445 1.258$ 146,187$2,140,331 1.913. 504 226,827 (5,004)119,210 102,613 (18.876)83,737 1.266$ 82,471 1999$1,978,826 1.689.997 288,829 7,000 83.672 212,157 212,157 1,417 LI210,740 1998$2,105,547 1,816.175 289,372 588 80,035 209,925 209,925 1.474 L 20845 2002 December 31, 2001 2000 (in thousands) -A -A ----BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation Net Electric utility Plant Total Assets$5,685,826 2.566.828$5,390,576 2.452 571$5,577,631 2.764.130$2.813 .50 361397.5$5,400,917 2.621.711$2 779,206$4. 675,5 1998$5,257,841 2,461.376$2,796,465 $4,344,68$4.457.032,93SiIM Common stock and Paid-in Capital Accumulated other comprehensive Income (LoSS)Retained Earnings Total Common Shareholder's Equity$ 783,684 (72,886)522.316$ 783,684 (196)401.297$ 783,684 398.086 S1A8181Z0$ 783,577 587.424$ 783,536 587. 500 Cumulative Preferred stock: Not subject to Mandatory Redemption $ 16,648 subject to Mandatory Redemption (a) 8.850 Total Cumulative Preferred stock $ 2549 Long-term Debt (a) $1,067,314 obligations under capital Leases (a) $&65,_626 Total capitalization and Liabilities $4,457,03$ 16,648 8.850$ 16,648 8.850$ 16,937 8.850$ 17,370 11,850 SZ5__M 25.4982~2~ S fL8--6&66$6.193,975 t$A__42, 635$4,675,159 (a) Including portion due within one year.1-1 -OHIO POWER COMPANY Management s Discussion and Analysis of Results of Operations Ohio Power Company (OPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 702,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR)which determines each company's percentage share of AEP Power Pool revenues and costs.Results of Operations Income Before Extraordinary Item increased$54 million or 33% in 2002 mainly due to reductions in operating expenses, predominantly fuel, and interest charges.Income Before Extraordinary Item increased$63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI)program recorded in 2000. In February 2001 the U.S. District Court forthe Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP s consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net Income was also favorably impacted by the growth in and strong performance by the wholesale business. The effects of the COLI decision in 2000 and favorable wholesale business in 2001 were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the economic downturn.Operating Revenues Operating Revenues increased 1% in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were: Increase (Decrease) From Previous Year (Dollars in Millions)2002 2001 Amount % Amount %Retail* $ 11 2 S(66) (8)wholesale Marketing 10 5 (19) (8)unrealized MTM 2 8 33 N.M.Other 1 1 (4) (5)Total wholesale Electricity* 24 2 (56) (5)Energy Delivery* 37 7 85 18 Sales to AEP Affiliates (46) (9) (71) (12)Total SL15 1 VA42) (2)* Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.During the summer months, cooling degree days increased 39%. For the fall season, heating degree days increased 32%. This 1-2 reflects a return to more normal weather conditions since 2001 weather was abnormally mild. Sales to AEP Affiliates decreased due to a 15% decrease in price, reflective of lower average fuel cost, while MWH sales rose slightly.Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool. This was the result of an affiliate being able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000.Operating Expenses Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel. Operating Expenses in 2001 also decreased 3%. This reduction was the result of lower Fuel and Income Taxes partially offset by amortization of transition regulatory assets.due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate s two nuclear units returning to service.Wholesale Electricity Purchased Power expense increased in 2002. This was the result of a 11% increase of MWH sales, partially offset by a decrease in price. In 2001 the increase was due to increases in MWH purchases from third parties because of the non-availability of associated nuclear power for resale to wholesale customers and to meet internal demand.AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18%increase of MWH purchased from affiliates with a slight decrease in the average price.The increase for 2001 was also a result of increased purchases through the AEP Power Pool.Changes in the Expenses were: Fuel wholesale Electricity Purchased Power AEP Affiliates Purchased Power Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes Total operating Expenses components of Operating Increase (Decrease) From Previous Year (dollars in millions)2002 2001 Amount % Amount %Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Spom plants, and boiler inspections at the Amos and Cardinal Plants.S C In 2001, the commencement of amortization 102) (15) 5(85) (11) of transition regulatory assets in connection 4 6 is 30 with the transition to customer choice and market-based pricing of retail electricity supply 8 14 12 23 under Ohio deregulation accounted for the 16 4 (4) (1)(6) (4) 18 15 significant increase in Depreciation and 9 4 84 54 Amortization expense.12 SLU4)10 12 (2)(10)(86)(6)(46)(3)The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWH generated. The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal.Fuel expense decreased 11 % in 2001 mainly The 2002 increase in Taxes Other Than Income Taxes is the result of increases in state excise tax created from a change in the base tax calculation. The decrease in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax.Income Taxes increased in 2002 due to an increase in both federal and state tax 1-3 -expenses. Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis.State taxes increased predominately as a result of the State of Ohio s tax legislation revision involving utility deregulation. Income Taxes decreased in 2001 due to an unfavorable ruling in AEP s suit against the government over interest deductions claimed relating to AEP s COLI program which was recorded in 2000 and a decrease in pre-tax book income.Nonoperating Income and Nonoperating Expense The major reason for the decrease in Interest Charges in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. Extraordinary Loss In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.Nonoperating Expenses decreased during 2002 due to reductions in variable incentive compensation expenses associated with wholesale trading.Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of an increase in the level of trading activity outside of the AEP System s traditional marketing area.The 2002 increase in Nonoperating Income Tax Expense is a result of the favorable tax benefit from the sale of the Ohio Coal companies in 2001. This event also caused the decrease for 2001.Interest Charges The 2002 decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.1-4 OHIO POWER COMPANY Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING REVENUES: Wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES INCOME BEFORE EXTRAORDINARY ITEM EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (See Note 2)NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK$1,058,250 589,673 465.202 2,113.125 584,730 67,385 71,154 416,533 136,609 248,557 176,247 113.581 1.814.796 298,329 51,953 28,567 18,010 83.682 220,023 220,023 1.258$ 218,765$1,034,026 552,713 511,366 2.098.105 686, 568 63,441 62,585 400,790 142,878 239,982 159,778 101,373 1.857. 395 240,710 70,108 53,802 (2,380)93.603 165,793 (18.348)147,445 1.258$ 146.187$1,090,297 467,587 582.447 2.140.331 771,969 48,657 50,741 404,410 124,735 155,944 169,527 187.521 1.913.504 226,827 57,163 44,009 18,158 119.210 102,613 (18.876)83,737 1,266 Statements of Comorehensive Income 2002 Year Ended December 31.(in thousands) 2001 023 $147,445 $NET INCOME $2 OTHER COMPREHENSIVE INCOME (LOSS)Foreign Currency Exchange Rate Hedge Minimum Pension Liability COMPREHENSIVE INCOME 3 The common stock of oPco is wholly owned by AEP.See Notes to Financial statements beginning on page L-1.1-5 220, (542)(72.148)147,333 (196)$147,249 I 2000;83,737 OHIO POWER COMPANY Statement of Retained Earninqs Year Ended December 31.2002 2001 (in thousands) $398,086 147.445 545.531 2000 Retained Earnings January 1 Net Income$401,297 220,023 621,320$587,424 83,737 671. 161 Deductions: cash Dividends Declared: Common stock Cumulative Preferred Stock: 4.08% series 4.20% series 4.40% Series 4-1/2% Series 5.90% series 6.02% Series 6.35% series Total Dividends 97,746 58 96 139 439 428 66 32 99,004 142,976 271,813 58 96 139 439 428 66 32 144,234 59 96 139 442 428 66 32 273,075 Retained Earnings December 31 see Notes to Financia7 statements beginning on page L-1.MZJI-6 $AO1,291 $3-9&JO 1-6 OHIO POWER COMPANY Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING CONTRACTS CURRENT ASSETS: cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for uncollectible Accounts Fuel Materials and Supplies Energy Trading Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES$3,116,825 905,829 1,114,600 260,153 288.419 5,685,826 2. 566.828 3.118.998 61,686 103.230 5,285 95,100 124,244 19,281 (909)87,409 85,379 92,108 12.083 519.980 568.641 84.497 SAA45 t932$3,007,866 891,283 1,081,122 245,232 165,073 5,390,576 2.452.571 2.938.005 62.303 99.706 8,848 84,694 148,563 20,409 (1,379)84,724 88,768 114,280 20,865 569.772 644.625 79.662 4A07 TOTAL ASSETS see Notes to Financial statements beginning on page L-1.1-7 OHIO POWER COMPANY December 31.2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock No Par value: Authorized 40,000,000 shares outstanding 27,952,473 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common Shareholder s Equity Cumulative Preferred Stock: Not subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year -General Long-term Debt Due within one Year Affiliated Companies short-term Debt Affiliated Companies Advances From Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued obligations under Capital Leases Energy Trading Contracts other Total CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS LONG-TERM ENERGY TRADING CONTRACTS REGULATORY LIABILITIES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 Statements beginning on page L-1.$ 321,201 462,483 (72,886)522. 316 1,233,114 16,648 8,850 917.649 2. 176.261 227,689 89,665 60,000 275,000 129,979 170,563 145,718 12,969 111,778 18,809 14,360 61,839 80.608 1,171,288 794.387 18.748 39,702 28.957 54,45,032$ 321,201 462,483 (196)401,297 1,184,785 16,648 8,850 1.203,841 2.414.124 130, 386 300,213 131,057 176, 520 5,452 126,770 17,679 16,405 98,081 90.431 962.608 797.889 21.925 50,459 16.682$4,3-9A4-0173 1-8 OHIO POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments for Noncash Items: Depreciation, Depletion and Amortization Deferred Income Taxes Deferred Investment Tax credits Deferred Fuel Costs (net)Extraordinary Loss Mark to Market of Energy Trading Contracts change in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Customer Deposits Taxes Accrued Disputed Tax and Interest Related to COLI Employee Benefit and other Noncurrent Liabilities Impairment Loss change in other Assets change in other Liabilities Net Cash Flows From Operating Activities $ 220,023 248,557 46,010 (3,177)(28,693)14,571 704 3,081 8,704 7,517 (14,992)110,298 1,757 (2,233)(133.154)478.973$ 147,445 252,123 215,833 (3,289)18,348 (59,833)51,640 4,852 264 9,887 (34,284)(96,331)(392,026)79,831 (107.704)86.756 S 83,737 200,350 (65,956)(3,399)(56,869)18,876 (5,614)51,430 46,645 45,311 56,069 31,540 60,919 110,494 145,573 (439,448)359.640 639,298 INVESTING ACTIVITIES: Construction Expenditures Proceeds From Sales of Property and other Investment in coal Companies Net Cash Flows used For Investing Activities FINANCING ACTIVITIES: Issuance of Long-term Debt change in Advances From Affiliates (net)Retirement of cumulative Preferred stock Retirement of Long-term Debt change in short-term Debt (net)Dividends Paid on Common stock Dividends Paid on cumulative Preferred stock Net cash Flows From (Used For)Financing Activities Net Decrease in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 (354,797)6,499 (348,298)(170,234)(140,000)275,000 (97,746)(1.258)(134.238)(3,563)8.848$ S5, (344,571)16,778 (32,115)(359.908)300,000 392,699 (297,858)(142,976)(1,258)250,607 (22,545)31. 393 (254,016)6,354 (247,662)74,748 (92,486)(182)(30,663)(194,918)(271,813)(1,262)(516, 576)(124,940)156.333 supplemental Disclosure: cash paid (received) for interest net of capitalized amounts was $81,041,000, $94,747,000 and$87,120,000 and for income taxes was $105,058,000, $(22,417,000) and $142,710,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $106,000,$2,380,000 and $17,005,000 in 2002, 2001 and 2000, respectively. See Notes to Financia7 Statements beginning on page L-1.1-9 11 OHIO POWER COMPANY Statements of CaDitalization December 31.2002 2001 (in thousands) $1.233.114 S1.184.785 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 3.762,403$25 par value -authorized shares 4,000,000 call Price shares December 31, Number of shares Redeemed outstanding series 2002 (a) Year Ended December 31. December 31. 2002 2002 2001 2000 Not Subject to Mandatory Redemption-S100 Par: 4.08% $103 ---14,595 4.20% 103.20 --276 22,824 4.40% 104 --432 31,512 4-1/2% 110 --2.181 97.546 subject to Mandatory Redemption-S100 Par (b): 5.90% (c) $ ---6.02% (d) ---6.35% (d) ---1,460 2,282 3,151 9. 755 16. 648 7,250 1, 100 500 8.850 1,460 2,282 3,151 9. 755 16. 648 7,250 1,100 500 8.850 72,500 11,000 5,000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 136,633 141,544 Installment Purchase Contracts 233,340 233,235 senior unsecured Notes 397,341 396,962 Notes Payable to Affiliated company 300,000 300,000 Junior Debentures -132,100 Less Portion Due within one Year (149.665) -Long-term Debt Excluding Portion Due within one Year 917,649 1.203.841 TOTAL CAPITALIZATION 52 626 S2,414,14Z (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends.(b) sinking fund provisions require the redemption of 35,000 shares in 2003 and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due dates. shares previously purchased may be applied to the sinking fund requirement. At the company s optioni all shares are redeemable at S100 per share plus accrued and unpaid dividends with at least 30 days notice beginning on or after November 1, 2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April 1, 2003 for the 6.35% series.(c) commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. shares previously redeemed may be applied to meet sinking fund requirements.(d) Commencing in 2003 and continuing through 2007 sinking fund provisions will require the redemption of 20,000 shares each year of the 6.02% series and 15,000 shares each year of the 6.35% series, in each case at $100 per share. All remaining outstanding shares must be redeemed in 2008. shares previously redeemed may be applied to meet the sinking fund requirements. See Notes to Financial Statements beginning on page L-1.1-10 OHIO POWER COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 6.75 2003 6.55 2003 6.00 2003 6.15 2003 (a) 2022 7.75 2023 7.375 2023 7.10 2023 7.30 2024 Unamortized Total April 1 S 29,850 October 1 27.315 November 1 12,500 December 1 20,000-February 10 -April 1 5,000 October 1 20,250-November 1 12,000 April 1 10,000 Discount (282)1135 633 S 29,850 27,315 12,500 20,000 5,000 5,000 20,250 12,000 10,000 (371)5141, 4A sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: December 31.2002 2001 (in thousands)(a) Redeemed on May 10, 2002.First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due 6.75 2004 7.00 2004 6.73 2004 6.24 2008 7-3/8 2038 unamortized Total July 1 $100,000 July 1 75,000 November 1 48,000 December 4 37,225 June 30 140,000 Discount (2.884)S37,4$100,000 75,000 48,000 37,225 140,000 (39263)Notes payable to parent company were as follows:% Rate Due 4.336% 2003 6.501% 2006 Total May 15 May 15 December 31.2002 2001 (in thousainds) S 60,000 S 60,000 240.000 240.000 Sa_,0 outstanding were as December 31.2002 2001 (in thousands) Junior debentures follows:% Rate Due Mason County, West Virginia: 5.45% 2016 December Marshall county, West Virginia: 5.45% 2014 July 1 5.90% 2022 April 1 6.85% 2022 June 1 Ohio Air Quality Development 5.15% 2026 May 1 unamortized Discount Total December 31.2002 2001 (in thousands) I S 50,000 S 50,000 50,000 50,000 35,000 35,000 50,000 50,000% Rate Due (a) 2025 (a) 2027 unamortized Total September 30 S -S 85,000 March 31 -50,000 Discount -(2.900)1 -si (a) Redeemed on July 24, 2002 At December 31, 2002 future annual long-term debt payments are as follows: 50,000 (1.660)12I33,34 50,000 (1.765)Under the terms of the installment purchase contracts, OPCo is required to pay amounts 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 149,665 223,000 240,000 459.475 1,072,140 4 826 1-11 OHIO POWER COMPANY Index to combined Notes to Financial statements The notes to OPCo s financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1.significant Accounting Policies Extraordinary Items and cumulative Effect Effects of Regulation Customer choice and Industry Restructuring Commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued operations Asset Impairments and Investment value Losses Benefit Plans Business segments Risk Management, Financial Instruments and Derivatives Income Taxes Supplementary Information Leases Lines of credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions Combined Footnote Reference Note 1 Note 2 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 13 Note 14 Note 16 Note 17 Note 18 Note 20 Note 22 Note 23 Note 24 Note 29 1-12 INDEPENDENT AUDITORS'REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying balance sheets and statements of capitalization of Ohio Power Company as of December 31, 2002 and 2001, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Ohio Power Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.1s1 Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 1-13 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Selected Consolidated Financial Data 2002 Year Ended December 31.2001 2000 1999 (in thousands) 1998 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest charges Net Income Preferred stock Dividend Requirements Gain on Reacquired Preferred stock Earnings Applicable to Common stock$ 793,647 708.926 84,721 (3,239)40.422 41,060 213$957,000 860.012 96,988 20 39.249 57,759 213$956,398 859.729 96,669 8,974 38,980 66,663$749,390 650.677 98,713 946 38.151 61,508 212$780,159 665.085 115,074 (91)38.074 76,909 212 213 1$ 40.848 LiZJ_.~ 1_0,A5I1 S-512% 9 6 $76-, 2002 December 31.2001 2000 (in thousands) 1999 1998 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$2,759,504 1.239,855$i,519,649 $1,76,69$2,695,099 1.184.443$1,510,656 $2,604,670 1.150.253$1.,454,417 $2,459,705 1,114.255$1 , 3A5,45Q 24$2,391,722 1.082.081 Total Assets$IAZ10 Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity$ 337,246 (54,473)116.474 S 399,247$ 337,246 142.994$ 480s2A0$ 337,246 137,688$ 474,934$ 337,246 139.237 S 476,483 S 337,246 142. 941 cumulative Preferred Stock: Not subject to Mandatory Redemption Preferred securities of subsidiary Trust Long-term Debt (a)$ 5. 27$LJ575000 S 75QQ0$ 545,437$ 451,129$_384,064 Total capitalization and Liabilities$1,748,911 $1.I 524, 846 S1,471,09 (a) Including portion due within one year.J-1 L. i PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Management s Narrative Analysis of Results of Operations Public Service Company of Oklahoma (PSO)is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing activities are conducted on PSO s behalf byAEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. Results of Operations In 2002, Net Income decreased by $17 million or 29% primarily resulting from reduced wholesale margins and increased depreciation expense.Changes in Operating Expenses Increase (Decrease) From Previous Year (dollars in millions)Amount %S(215.3) (47)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 23.3 45.7 (4.1)1.9 96 104 (3)4 5.6 7 2.1 (10.3)S(514)7 (30)(18)N.M. = Not Meaningful The decrease in Fuel expense in 2002 was primarily due to lower market prices for natural gas and fuel oil, and deferral of underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and to the amortization of previously overrecovered fuel costs.Changes in Operating Revenues Operating revenues decreased in 2002 as a result of reduced wholesale margins, a decline in fuel recovery revenue and decreases due to the interchange cost reconstruction (ICR) adjustments (see Note 6).Increase (Decrease) From Previous Year (dollars in millions)Amount %wholesale Electricity* S(149.7) (23)Energy Delivery* 13.6 5 sales to AEP Affiliates t27.3) (74)Total operating Revenues S(163) (17)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.The increase in Electricity Marketing Purchased Power expense in 2002 resulted mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices.The increase in the AEP Affiliates Purchased Power expense in 2002 resulted mainly from the ICR adjustments (see Note 6).Other Operation expense decreased in 2002 primarily due to lower transmission expenses and decreased factoring expenses due to reduced revenues.Maintenance expense increased, in 2002 largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002.Depreciation and Amortization expense increased in 2002 primarily due to the additional depreciable capitalized costs involved in repowering NortheastStation Units 1 & 2 completed in 2001.Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in ad valorem taxes.J-2 Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.Other Changes Nonoperating Expenses increased primarily due to the write-down of certain non-utility investments in 2002.J-3 --t PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Income Year Ended December 31.2002 OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAX EXPENSE (CREDIT)INTEREST CHARGES$508,661 275,547 9,439 793,647 246,199 47,507 89,454 133,538 48,060 85,896 34,077 24.195 708.926 84,721 1,920 6,971 (1,812)40.422 ZO21 (in thousands) $658,352 261,877 36.771 957.000 461,470 24,187 43,758 137,678 46,188 80,245 31,973 34,513 860.012 96,988 2,112 1,740 352 39.249 2000$696,626 245,124 14, 64 8 956. 398 402,933 88,088 60,788 121,697 45,858 76,418 28,688 35,259 859.729 96,669 8,807 1,139 (1,306)38.980 NET INCOME GAIN ON REACQUIRED PREFERRED STOCK LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 41,060 1 213 57,759 213 ,$L5 66,663 212$ 66A S5$ 40,848 Consolidated Statements of Comprehensive Income Year Ended December 31.2002 2001 2000 (in thousands) $ 41,060 $57,759 $66,663 NET INCOME OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges Minimum Pension Liability COMPREHENSIVE INCOME (LOSS)(42)(54.431)$ (13.413)$5ZL75-9 I The common stock of P50 is owned by a wholly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-4 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Retained Eaminqs Year Ended December 31, 2002 2001 (in thousands) $137,688 57,759 2000$139,237 66,663 BEGINNING OF PERIOD NET INCOME DEDUCTIONS: capital Stock Gains Cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$142,994 41,060 (1)67,368 213$116,474 52,240 213 68,000 212$142,994 1IaL&6 The common stock of P50 is owned by a who ly owned subsidiary of AEP.See Notes to Financial Statements beginning on page L-1.J-5 It i -PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$1,040,520 432,846 990,947 206,747 88.444 2,759,504 1.239.855 1.519.649 OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable: Customers Affiliated companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS 4.481 16,774 31,687 14,139 (84)19,973 37,375 76,470 3,841 2.735 202.910$1,034,711 427,110 972,806 203,572 56.900 2,695,099 1,184.443 1,510,656 41.020 21. 354 5,795 31,144 10,905 (44)21,559 36,785 756 26,259 2.368 135. 527 REGULATORY ASSETS 26. 150 DEFERRED CHARGES 18.117 TOTAL ASSETS$1. 748. 911 See Notes to Financial statements beginning on page L-1.J-6 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CAPTTALIZATION AND LIARILTTIFS December 31, 2002 2001 (in thousands) CAPITALIZATION: Common Stock $15 Par value: Authorized shares: 11,000,000 Issued Shares: 10,482,000 outstanding Shares: 9,013,000 Paid-in capital Accumulated Other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Cumulative Preferred stock Not subject to Mandatory Redemption Pso-obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO Long-term Debt TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year Advances from Affiliates Accounts Payable General Accounts Payable Affiliated Companies Customer Deposits Over-Recovered Fuel Costs Taxes Accrued Interest Accrued Energy Trading and Derivative Contracts other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS REGULATORY LIABILITIES AND DEFERRED CREDITS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.S 157,230 180,016 (54,473)116,474 399. 247$ 157,230 180,016 142.994 480.240 5,267 5,267 75,000 445.437 924.951 54.761 100,000 86,105 61,169 78,076 21,789 6,854 6,979 3,260 24. 957 389.189 341.396 32.201 32.611 1,581$1,776,690 75,000 345.129 905.636 7,263 106,000 123,087 72,759 40,857 21,041 9,476 18,150 7,298 31,718 12,216 442.602 296.877 33,992 49.080 13.461$1. 748, 911.J-7 --PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Cash Flows Year Ended December 31.2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments to Reconcile Net Income to Net Cash from operating Activities: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits changes in Certain Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies other Property and Investments Accounts Payable Taxes Accrued Fuel Recovery Transmission Coordination Agreement settlement changes in Other Assets changes in Other Liabilities Net Cash From Operating Activities $ 41,060 85,896 75,659 (1,791)(3,737)996 (419)25,629 (11,296)(85,190)2,215 (6,928)122.094$ 57,759 80,245 (17,751)(1,791)21,405 (589)(2,809)(55,319)16,491 51,987 (9,120)9.351 149,859 S 66,663 76,418 25,453 (1,791)(28,826)677 7,994 89,330 (16,821)(36,798)(15,063)4,482 65.6193 165.615 INVESTING ACTIVITIES: Construction Expenditures Proceeds from Sale of Property other Items Net cash used For Investing Activities 963 (88.402)FINANCING ACTIVITIES: Issuance of Long-term Debt Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on cumulative Preferred stock Net cash From (used For)Financing Activities 187,850 (106,000)(36,982)(67,368)(213)(22,713)(124,520)(359)(124,879)(20,000)41,967 (52,240)(213)(30, 486)(176,851)(176.851)105,625 (20,000)1,951 (68,000)(212)Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 10,979 5.795$1 6977 (5,506)11.301 8,128 3 .173 SL==I~i supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $38,620,000, $38,250,000 and$33,732,000 and for income taxes was ($38,943,000), $38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively. See Notes to Financial statements beginning on page L-1.J-8 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) $ 399.247 $480.240 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: Cumulative $100 par value authorized redeemable at the option of PSO upon 30 days notice.Call Price December 31, Number of shares Redeemed Series 2002 Year Ended December 31, 2002 2001 2000 Not subject to Mandatory Redemption: 4.00% $105.75 6 -25 4.24% 103.19 ---TRUST PREFERRED SECURITIES PSo-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior subordinated Debentures of PSO, 8.00%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts senior unsecured Notes Less Portion Due Within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION see Notes to Financial Statements beginning on page L-1.shares 700,000, Shares outstanding December 31. 2002 44,600 8,069 4,460 807 5.267 75.000 298,079 47,358 200,000 (100.000)445.437 4,460 807 5. 267 75.000 297,772 47,357 106,000 (106. 000)345.129 J-9 --PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Lona-term Debt First mortgage bonds outstanding were as follows: December 31.2002 2001 (in thousands) % Rate Due 6.25 2003 7.25 2003 7.38 2004 6.50 2005 7.38 2023 unamortized April 1 July 1 December 1 June 1 April 1 Discount S 35,000 65,000 50,000 50,000 100,000 (1.921)S29Bs29 S 35.000 65,000 50,000 50,000 100, 000 (2 228)Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31.2002 2001 (in thousands) % Rate Due (a)i 2002 (b) 2032 TOTAL December 31.2002 2001 (in thousands) November 21 S -S106,000 December 31 200 000 -520 00M 16 0 (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was $2.775%.(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) Rat Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 -December 1 S 1,000 S 1,000 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total$100,000 50,000 50,000 1,000 346. 360 547, 360 (1.923)545 437 Oklahoma Development Finance Authority (ODFA): 4.875 2014 -June 1 Red River Authority of Texas: 6.00 2020 June 1 Unamortized Discount Total i 33,700 33,700 12,660 12,660 (2) (3),Al 3-58 547 357 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of PSO.J-1 0 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Index to Combined Notes to Consolidated Financial Statements The notes to PSO s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to P50. The combined footnotes begin on page L-1.combined Footnote Reference significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 Benefit Plans Note 14 Business segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric utility Plant Note 28 Related Party Transactions Note 29 J-1 1 INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiary as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require thatwe plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.IsI Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 J-12 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data 2002 INCOME STATEMENTS DATA: operating Revenues operating Expenses operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item Extraordinary Loss Net Income Preferred stock Dividend Requirements LOSS on Reacquired Preferred stock Earnings Applicable to Common stock$1,084,720 942.251 142,469 (309)59,168 82,992 82,992 229 Year En 2001$1,101,326 955,119 146,207 741 57, 581 ided December 31, 2000 (in thousands) $1,118,274 $989.996 128,278 3,851 59,457 _1999 971,527 824,465 147,062 (1,965)58,892 86,205 (3,011)83,194 229----1998$ 952,952 802,274 150,678 2,451 5,9135 97,994 97,994 705 89,367 72,672 89,367 72,672 229 229$ 8J39& U$ 72,443_$ --- a33 December 31, 2002 2001 2000 (in thousands) 1999 BALANCE SHEETS DATA: Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Total Assets Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder's Equity Preferred stock$3,596,174
- 1. 697. 338$2 2S L67I5$ 380,663 (53,683)334,789$3,460,764
$3,319,024 $3,231,431 1,550,618 1,457,005-$i Q0,146 $1&862019$L380,616 $ 380,663$ 380,663 $ 380,663 1.384.242 ,2 16762:$ 380,663 283, 546 1998$3,157,911 1.317.057-£2 IQ -85A'25$ 380,663 296, 581$_677L244 308,915 293,989 S$_&6W5i8 $-6!A.-5i2 S-664,ZO0.11 1 LQ1 $ 4,70-1~ 2QTrust Preferred securities Long-term Debt (a)Total capitalization and Liabilities $__11O0,Q $ 110,000 A11 4 QQ00£_lUXlQQQ_$__M-t645 S& 6A45,963 A15&£$Z2 0-8,M~z$2,3Q0,676 $ 2 58 3&5102 6,162$2 Q8Z,258 (a) Including portion due within one year.K-1 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management s Discussion and Analysis of Results of Operations Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing activities are conducted on SWEPCo s behalf by AEPSC.SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP s electric power transactions with other utility systems and power marketers. Results of Operations In 2002, Net Income decreased $6.4 million or 7% primarily resulting from reduced margins.In 2001, Net Income increased $16.7 million or 23% resulting primarily from the favorable impact of our sharing in AEP s power marketing activities for a full year.Changes in Operating Revenues Operating Revenues decreased 2% for 2002 primarily due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation ($12.6 million) and the positive impact of the interchange cost reconstruction (ICR) adjustments (see Note 6).In 2001, Operating Revenues decreased $17 million or 2% resulting from unfavorable wholesale marketing and trading conditions. Changes in Operating Expenses Increase (Decrease) From Previous Year (dollars in millions)2002 2001 Amount % Amount X S(69) (15) S(41) (8)26 143 (40) (69)Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes Total 26 165 18 10 (8) (10)2 19 12 7-(1)3 3 15 14 (1)(8)(1)(20)(1)2 16£LI)4 60 (4)Increase (Decrease) From Previous Year (dollars in millions 2002 2001 Amount % Amount %wholesale Electricity* $(25) (4) S(21) (3)Energy Delivery* 15 5 (12) (3)Sales to AEP Affiliates .7) (9) 16 26 Total operating Revenues £-1Z) (2) ILU) (2)*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.Fuel expense decreased in 2002 due to a reduction in MWH generated and a decrease in the cost of fuel, primarily natural gas.Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. K-2 L.In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was mainly due to reduced prices caused by decreased electricity demand.The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in 2002 by$4.3 million. Other Operation expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other Operation expense increased also as a result of the Dolet Hills mining operation in June 2001.The 10% decrease in Maintenance expense in 2002 is primarily a result of higher storm and tree trimming related expenses in 2001.The increase in Depreciation and Amortization expense in 2002 is primarily due to the addition of Dolet Hills in June 2001, which added $3.0 million of additional expense in 2002. Depreciation and Amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income. In 2001, the increase in income tax expense was primarily due to an increase in pre-tax income.K-3 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity Energy Delivery Sales to AEP Affiliates TOTAL OPERATING REVENUES OPERATING EXPENSES: Fuel Purchased Power: wholesale Electricity AEP Affiliates other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES$ 664,185 348,236 72,299 1.084,720 388,334 44,119 42,022 189,024 66,855 122,969 55,232 33,696 942.251$ 689,085 333,004 79,237 1.101.326 457,613 18,164 15,858 171,314 74,677 119,543 55,834 42,116 955.119$ 710,200 344,950 63,124 1.118.274 498,805 58,518 13,338 159,459 75,123 104,679 53,830 26,244 989, 996 OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 NONOPERATING EXPENSES 1,797 4,512 3,229 542 5,487 3,112 (1,476)NONOPERATING INCOME TAX EXPENSE (CREDIT)1,772 INTEREST CHARGES 59.168 57, 581 59.457 NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 229 S 82.e763 229 S 89,138 229 S 72.443 Consolidated Statements of Comprehensive Income 2002 Year Ended December 31.2001 2000 (in thousands) --- ---NET INCOME $82,992 $89,36 OTHER COMPREHENSIVE INCOME (LOSS): cash Flow Power Hedges (48) -Minimum Pension Liability (53.635) -COMPREHENSIVE INCOME "24.309 S___36 The common stock of SWEPco is owned by a who77y owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.7$72,672$72 f92 K-4 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31, 2002 2001 2000 (in thousands) BALANCE AT BEGINNING OF PERIOD NET INCOME$308,915 82,992 DEDUCTIONS: cash Dividends Declared: Common stock Preferred stock BALANCE AT END OF PERIOD$293,989 $283,546 89,367 72,672 74,212 62,000 229 229$ 3C&4915 $s91I9&9 56,889 229 The common stock of SwEPCo is owned by a wholly owned subsidiary of AEP.See Notes to Financial statements beginning on page L-1.K-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production Transmission Distribution General Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT OTHER PROPERTY AND INVESTMENTS LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS CURRENT ASSETS: Cash and cash Equivalents Accounts Receivable: Customers Affiliated Companies Allowance for uncollectible Accounts Fuel Inventory Materials and supplies Under-recovered Fuel Costs Energy Trading and Derivative Contracts Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES TOTAL ASSETS see Notes to Financia7 statements beginning on page L-1.$1,503,722 575,003 1,063,564 378,130 75,755 3,596,174 1.697. 338 1.898.836 5,978 5,119 2,069 62,359 19,253 (2,128)61,741 33,539 2,865 4,388 17,851 201.937 49,233 47. 572$2,20,65$1,429,356 538,749 1,042,523 376,016 74.120 3,460,764 1.550.618 1.910,146 43.000 24,508 5,415 43,133 12,069 (89)52,212 32,527 8,839 30,139 18,716 202.961 52. 308 67, 753$2,300,676 K-6 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CAPITALIZATION AND LIABILITIES December 31.2002 2001 (in thousands) CAPITALIZATION: Common stock $18 Par value: Authorized 7,600,000 Shares Outstanding 7,536,640 shares Paid-in capital Accumulated other Comprehensive Income (Loss)Retained Earnings Total Common shareholder s Equity Preferred stock SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo Long-term Debt TOTAL CAPITALIZATION $ 135,660 245,003 (53,683)334,789 661,769 4,701 110,000 637.853 1.414.323 78.494$ 135,660 245,003 308.915 689,578 4,701 110,000 494,688 1. 298.967 40,109 OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES: Long-term Debt Due within One Year Advances from Affiliates, net Accounts Payable General Accounts Payable Affiliated Comp;Customer Deposits Taxes Accrued Interest Accrued Energy Trading and Derivative Cont over-recovered Fuel other TOTAL CURRENT LIABILITIES ani es 55,595 23,239 62,139 58,773 20,110 19,081 17,051 3,724 17,226 34, 565 311.503 racts 150, 595 117,367 71,810 37,469 19,880 36,522 13,027 36,297 5,487 26,074 514.,528 369.78 48.714 13.,127 15,45S0 DEFERRED INCOME TAXES 341.064 DEFERRED INVESTMENT TAX CREDITS 44,190 REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 1.806 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS COMMITMENTS AND CONTINGENCIES (Note 9)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financia7 statements beginning on page L-1.$2,208,675 2LINJ7U K-7 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income Adjustments to Reconcile Net Income to Net cash Flows From Operating Activities: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax credits Mark-to-Market Energy Trading and Derivative Contracts Changes in Certain Current Assets and Liabilities: Accounts Receivable (net)Fuel, Materials and supplies Accounts Payable Taxes Accrued Transmission coordination Agreement Settlement Fuel Recovery change in other Assets change in other Liabilities Net cash Flows From Operating Activities $ 82,992 122,969 (3,134)(4,524)$ 89,367 119,543 (31,396)(4,453)(1,151) (10,695)(24,371)(10,541)11,633 (17,441)17,713 24,257 12.16 210.563 (11,447)(19,578)(34,489)25,298 34,423 1,323 11, 714 169.610 S 72,672 104,679 14,653 (4,482)7,795 (1,254)22,103 43,962 (13,150)(24,406)(38,357)54,414 (37.001)201.628 INVESTING ACTIVITIES: Construction Expenditures Purchase of Dolet Hills Mining operations other Net cash Flows used For-Investing Activities (111,775)1.134 (110.641)FINANCING ACTIVITIES: Issuance of Long-term Debt Redemption of Preferred stock Retirement of Long-term Debt Change in Advances From Affiliates (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net cash Flows From (used For)Financing Activities Net Increase (Decrease) in cash and cash Equivalents Cash and Cash Equivalents January 1 cash and cash Equivalents December 31 198,573 (150,595)(94,128)(56,889)(229)(103,268)(3,346)5.415 (111,725)(85,716)(411)(197.852)(595)106,786 (74,212)(229)31.750 3,508 1.907 (120,671)446 (120.225)149,360 (1)(45,595)(124,074)(62,000)(229)(82.5 39)(1,136)3.043 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000 and$51,111,000 and for income taxes was $60,451,000, $49,901,000 and $27,994,000 in 2002, 2001, and 2000, respectively. See Notes to Financia7 statements beginning on page L-1.K-8 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31.2002 2001 (in thousands) S 661.769 $ 689.578 COMMON SHAREHOLDER S EQUITY PREFERRED STOCK: $100 par value authorized shares 1,860,000 call Price December 31, Number of shares Redeemed series 2002 Year Ended December 31E 2002 2001 2000 Not subject to Mandatory Redemption: 4.28% $103.90 ---4.65% $102.75 ---5.00% $109.00 --12 Shares Outstanding December 31. 2002 7,386 1,907 37,715 TRUST PREFERRED SECURITIES SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of SWEPCo, 7.875%, due April 30, 2037 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Less Portion Due within one Year Long-term Debt Excluding Portion Due within one Year TOTAL CAPITALIZATION See Notes to Financial statements beginning on page L-1.740 190 3.771 4.701 110.000 315,420 179,183 198,845 (55.595)637. 853 11_41Mv23 740 190 3. 771 110.000 315,449 179,834S 150,000 (150. 595)494.688 K-9 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2002 2001 (in thousands) % Rate Due 6-5/8 2003 7-3/4 2004 6.20 2006 6.20 2006 7.00 2007 7-1/4 2023 6-7/8 2025 unamortized February 1 June 1 November 1 November 1 Se tember Juqy 1 October 1 Discount S 55,000 40,000 5, 505 1,000 I 90,000 45,000 80 000 (1.085)S315-420 S 55,000 40,000 5,650 1,000 90,000 45,000 80,000 (1.201)Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior unsecured notes outstanding were as follows: First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. % Rate Due 4.50 2005 July 1 (a) 2002 March 1 Unamortized Discount December 31, 2002 2001 Otiw thousandcs-) S200,000 S --150,000_. 198;85 5) 0OO (a)A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.311%.Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2002 2001 (in thousands) % Rate Due DeSoto County: At December 31, 2002 future annual long-term debt payments are as follows: 2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) S 55,595 52,885 200,595 6,520 90,450 287.695 693,740 (292)S69344 7.60 2019 January 1 S 53,500 Sabine:$ 53,500 6.10 2018 April 1 Titus County: 6.90 2004 -November 1 6.00 2008 -January 1 8.20 2011 August 1 81,700 81,700 See Note 25 for discussion of Trust Preferred Securities issued by a wholly-owned statutory business trust of SWEPCo.12,290 12,290 12,620 13,070 17,125 17,125 Unamortized Premium SIZR-183 S 179-,3A K-10 i-SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to SWEPCo s consolidated financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to SWEPCo.The combined footnotes begin on page L-1.Significant Accounting Policies Extraordinary Items and Cumulative Effect Goodwill and other Intangible Assets Merger Rate Matters Effects of Regulation Customer choice and Industry Restructuring commitments and Contingencies Guarantees sustained Earnings Improvement Initiative Acquisitions, Dispositions and Discontinued Operations Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes Leases Lines of credit and Sale of Receivables Unaudited Quarterly Financial Information Trust Preferred Securities Jointly owned Electric utility Plant Related Party Transactions combined Footnote Reference Note 1 Note 2 Note 3 Note 4 Note 6 Note 7 Note 8 Note 9 Note 10 Note 11 Note 12 Note 14 Note 16 Note 17 Note 18 Note 22 Note 23 Note 24 Note 25 Note 28 Note 29 K-1I INDEPENDENT AUDITORS REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31,2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002.These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformitywith accounting principles generallyaccepted in the United States of America.Is/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 K-12 COMBINED NOTES TO FINANCIAL STATEMENTS Index to Combined Notes to Financial Statements The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 2. Extraordinary Items and Cumulative Effect AEP, APCo, CSPCo, OPCo, SWEPCo, TCC, TNC 3. Goodwill and Other Intangible Assets AEP, SWEPCo 4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC, TNC 5. Nuclear Plant Restart AEP, I&M 6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC 7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 8. Customer Choice and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo, TCC, TNC 9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 11. Sustained Earnings Improvement Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 12. Acquisitions, Dispositions and Discontinued AEP, OPCo, SWEPCo, TCC, TNC Operations
- 13. Asset Impairments and Investment Value AEP, APCo, CSPCo, I&M, KPCo, OPCo, TCC, TNC Losses 14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 15. Stock-Based Compensation AEP 16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 17. Risk Management, Financial Instruments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo and Derivatives PSO, SWEPCo, TCC, TNC L-1
- 18. Income Taxes 19. Basic and Diluted Earnings Per Share 20. Supplementary Information
- 21. Power and Distribution Projects 22. Leases 23. Lines of Credit and Sale of Receivables
- 24. Unaudited Quarterly Financial Information
- 25. Trust Preferred Securities
- 26. Minority Interest in Finance Subsidiary
- 27. Equity Units 28. Jointly Owned Electric Utility Plant 29. Related Party Transactions
- 30. Subsequent Events (Unaudited)
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP AEP, APCo, CSPCo, I&M, OPCo AEP AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, PSO, SWEPCo, TCC AEP AEP* CSPCo, PSO, SWEPCo, TCC, TNC AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP L-2
- 1. Significant Accounting Policies: Business Operations AEP s (the Company s)principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP s eleven domestic electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC, are SEC registrants.
AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent, other commodities in the United States and Europe. In addition,theCompanysdomestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.International operations include supply of electricity and other non-regulated power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale.The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. See Note 13 for further discussion of changes in our communications related business and other business operations announced in 2002.Rate Regulation AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated bythe authorities of that country and are generally subject to price controls.Principles of Consolidation AEP s consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially controlled subsidiaries. The consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC include the registrant and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income forAEP and nonoperating income for the registrant subsidiaries. Basis of Accounting -As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71,"Accounting for the Effects of Certain Types of Regulation, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia byAPCo in June 2000, in Texas byTCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8, "Customer Choice and Industry Restructuring for additional information. Use of Estimates -The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates. L-3 Property, Plant and Equipment Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses. Plants are tested for impairment as required under SFAS 144. See Note 13.Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization -AFUDC is a noncash, nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. The amounts of AFUDC for 2002, 2001 and 2000 were not significant. Effective with the discontinuance of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia, West Virginia and other non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized were not material in 2002, 2001, and 2000.Depreciation, Depletion and Amortization -Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, otherthan coal-mining property, and is calculated largely through the use of composite rates by functional class as follows: Functional Class of ProDertv Production: Steam-Nuclear Steam-Fossil -Fi red Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Functional class of ProDerty Production: Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution other Annual Composite Depreciation Rates Ranges 2002 2.5% to 3.4%2.6% to 4.5%1.9% to 3.4%1.7% to 3.0%3.3% to 4.2%1.8% to 9.9%Annual Composite Depreciation Rates Ranges 2001 2.5% to 3.4%2.5% to 4.5%1.9% to 3.4%1.7% to 3.1%2.7% to 4.2%1.8% to 15.0%Annual Composite Depreciation Rates Ranges 2000 2.8% to 3.4%2.3% to 4.5%1.9% to 3.4%1.7% to 3.1%3.3% to 4.2%2.5% to 7.3%L4 The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which were as follows: Nuclear Steam Hyd ro Transmission Distribution General AEGCo APCo CSPco I&M KPCo OPCo PSO SWEPCo TCC TNC 3.4 2.5 3.5%3.4 3.2 4.5 3.8 3.4 2.7 3.4 2.6 2.8 2.9 3.4 2. 7 1.9 2.2 2.3 1.9 1.7 2.3 2.3 2.7 2.3 3.1 3.3 3.6 4.2 3.5 4.0 3.4 3.6 3.5 3.3 2.8%3.1 3.2 3.8 2.5 2.7 6.3 4.7 4.0 6.8 Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages. These costs are included in the cost of coal charged to fuel expense for coal used by utility operations. Current average amortization rates are $0.32 per ton in 2002,$3.46 per ton in 2001 and $5.07 per ton in 2000.In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in 2002.Cash and Cash Equivalents -Cash and cash equivalents include temporary cash investments with original maturities of three months or less.Inventory Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market.Materials and supplies inventories are carried at average cost.Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be carried atfairvalue until December31,2002, and inventory purchased from October 26 through December 31, 2002 was carried at the lower of cost or market. Effective January 1, 2003, all natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held in connection with trading operations by approximately $39 million. This change will be accounted for as a cumulative effect of a change in accounting principle. Accounts Receivable AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for certain non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreementwith a group of banks and commercial paper conduits. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the companys balance sheet. See Note 23 for further details.Foreign Currency Translation -The financial statements of subsidiaries outside the U.S. which are included in AEP s consolidated financial statements are measured using the local currency as the functional currency and translated into U.S.dollars in accordance with SFAS 52 "Foreign Currency Translation .Assets and liabilities are L-5 translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on AEP s Consolidated Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual currency transaction gains and losses are recorded in income.Deferred Fuel Costs -The cost of fuel consumed is charged to expense when the fuel is burned.Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulators review and approval. The amount of deferred fuel costs under fuel clauses forAEP was $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "Effects of Regulation .We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings. This is also true for certain of AEP s Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 6, "Rate Matters and Note 8,"Customer Choice and Industry Restructuring for further information about fuel recovery.Revenue Recognition -Regulatory Accountinq -The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds)are recorded to reflect the economic effects of regulation by matching expenses with their recoverythrough regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period.Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made.When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.Traditional Electricity Supply and Deliverv Activities -Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and L-6 storage revenues also include the accrual of earned, but unbilled andlor not yet metered gas.Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133.Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves.Energy Marketinq and Trading Transactions In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps.We use the mark-to-market method of accounting for trading activities as required by EITF Issue No.98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net in revenues as unrealized gains and losses from mark-to-marketvaluations. When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. In October 2002, management announced plans to focus on wholesale markets around owned assets.All of the registrant subsidiaries except AEGCo participate in AEP s wholesale marketing and trading of electricity. For l&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash.Where this amount is recorded on the income statement depends on whether the contract s delivery points are within or outside of AEP s traditional marketing area. For contracts with delivery points in AEP s traditional marketing area, the total gain or loss realized in cash for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contracts with delivery points outside of AEP s traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income.Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP s traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP s traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP s traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP s traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP s traditional marketing area are included in nonoperating income on a net basis.The trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in AEP s revenues until the contracts settle. When these contracts settle, the net proceeds are recorded in revenues and reverse the prior cumulative unrealized net gain or loss.APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized L-7 gains and losses, as well as the net proceeds upon settlement, in nonoperating income.The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked-to-market based mainly on AEP-developed valuation models. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Such valuation adjustments provide for a better approximation of fair value. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with AEP-developed price models.As explained above, the effect on AEP s Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP s regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate. Construction Projects for Outside Parties Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue in proportion to costs incurred compared to total estimated costs.Debt InstrumentHedging and RelatedActivities In order to mitigate the risks of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges.There were no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17 'Risk Management, Financial Instruments and Derivatives for further discussion of the accounting for risk management transactions. Levelization of Nuclear Refueling Outage Costs -In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M s Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and 'ending with the beginning of the next outage.Maintenance Costs Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.See below for an explanation of costs deferred in connection with an extended outage at l&M s Cook Plant.Amortization of Cook Plant Deferred Restart Costs -Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and l&M.Other Income and Other Expenses Other Income includes non-operational revenue including area business development and river transportation, equity earnings of non-consolidated subsidiaries, gains on dispositions of L-8 property, interest and dividends, an allowance for equity funds used during construction (explained above) and miscellaneous income. Other Expenses includes non-operational expense including area business development and river transportation, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses.AEP Consolidated other Income and Deductions amortized over the life of the regulated plant investment. Excise Taxes AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement. December 31, 2002 2001 2000 (in millions)OTHER INCOME: Equity Earnings Non-operational Revenue Interest and Miscellaneous Income Gain on sale of Frontera Gain on sale of Retail Electric Provider Total other Income OTHER EXPENSES: Property Taxes and Miscellaneous Expenses Non-operational Expenses Fiber optic and Datapult Exit Costs Provision for Loss -Airplane Total other Expenses S 104 S 123 187 123$ 22 71 Debt and Preferred Stock Gains and losses 25 16 2 from the reacquisition of debt used to finance-73 -domestic regulated electric utility plant are 129 --generally deferred and amortized over the S 45 S- ___ remaining term of the reacquired debt in accordance with their rate-making treatment. If debt associated with the regulated business is S 142 S 68 5 28 refinanced, the reacquisition costs attributable to 179 56 49 the portions of the business that are subject to-49 -cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the-14 term of the replacement debt commensurate with S1321 s1&z L z their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to EP System follows the SFAS 71 are reported as a Loss on Reacquired ting for income taxes as Debt, an extraordinary item on the Consolidated lAccounting for Income Statements of Operations of AEP and TCC. See iility method, deferred discussion of SFAS 145 in New Accounting 'ded for all temporary Pronouncements section of this note for new book cost and tax basis treatment effective in 2003.Income Taxes -The AE liability method of accoun prescribed by SFAS 109, Taxes. Under the liat income taxes are provi differences between the I of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense.Investment Tax Credits -Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is included in interest charges.Where rates are regulated, redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistentwith the timing of its inclusion in rates in accordance with SFAS 71.L-9 Goodwill and Intangible Assets In June 2001, the FASB issued SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo.SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30,2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note 3 for further discussion of our components of goodwill and intangible assets.SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1,2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142.In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002.Nuclear Trust Funds Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers funds and to allow those funds to earn a reasonable return. In general, limitations include:.Acceptable investments (rated investment grade or above)* Maximum percentage invested in a specific type of investment
- Prohibition of investment in obligations of the applicable company or its affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115,"Accounting for Certain Investments in Debt and Equity Securities. Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liabilityaccount forthe nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.Comprehensive Income (Loss) -Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other, events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by L-1 0 -owners and distributions to owners.Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.Components of Other Comprehensive Income (Loss) Other comprehensive income (loss) is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income (Loss) for AEP.segment as viewed by the chief operating decision-maker. See Note 16, "Business Segments for further discussion and details regarding segments.Common Stock Options At December 31, 2002, AEP has two stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 15. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. No stock-based employee compensation expense is reflected in AEP s earnings, as all options granted under these plans had exercise prices equal to or above the marketvalue of the underlying common stock on the date of grant. The following table illustrates the effect on AEP s net income (loss)and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation , to stock-based employee compensation. Foreign Currency Adjustments unrealized Losses on Securities unrealized Gain on Hedged Derivatives Minimum Pension Liability December 31, 2002 2001 2000 (in millions)S 4 S(113) S (99)(2) --(16) (3) -(595) (c ) (4)Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of December 31, 2002 and 2001 is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the year ended December 31, 2000 was zero.Year Ended December 31, 2002 2001 2000 (in millions except per share data)$ (519) S 971 $ 267 components December 31, 2002 2001 (in thousands) Net Income(Loss), as reported Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro forma net income (loss)Earnings (Loss) per share: Basic as reported Basic pro forma Diluted as reported Diluted pro forma L__)5Th57) 5.3 0 (12)S-95 LZ34 cash Flow Hedges: APCO cSPco I&M KPCo oPco PSO SWEPCo TCC TNC Minimum Pension Liability: APCO cSPco INM KPCO oPco PSO SWEPCo TCC TNC S(1,920)(267)(286)322 (738)(42)(48)(36)(15)S (340)(3,835)(1,903)(196)S-UI5) S2Z97 SO. S3_____) SIZAZg OM18 S(70,162)(59,090)(40,201)(9,773)(72,148)(54,431)(53,635)(73,124)(30,748)Earnings Per Share (EPS) AEP calculates earnings (loss) per share in accordance with SFAS No. 128, "Earnings Per Share (see Note 19). Basic earnings (loss) per common share is calculated bydividing neteamings (loss) available to common shareholders by the weighted average number of common shares outstanding during the'-period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming Segment Reporting The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business L-1 I conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. Basic and diluted EPS are the same in 2002, 2001 and 2000.AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS.Reclassification Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts and Emerging Issues Task Force Topic D-43,"Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.39 .Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy.Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.New Accounting Pronouncements recent market transactions and cash flow projections. As a result of that testing, AEP determined that there was a net transitional impairment loss, which is reported as a cumulative effect of a change in accounting principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets.SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets.In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized. Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP s and SWEPCo s intangible assets.SFAS 143, "Accounting for Asset Retirement Obligations , is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured atfairvalue and is capitalized as part of the related assets capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest)will be recognized each period as an operating expense in the statement of operations. The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects l&M and TCC) and possibly other obligations. AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities.SFAS 142, "Goodwill and Other Intangible Assets, was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations. The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on L-1 2 In addition, the regulated transmission and distribution entities have asset retirement obligations related to the final retirement of certain transmission and distribution lines. There are also underground storage tanks located at various sites throughout the AEP System and PCB s are contained in certain transformer rectifier sets at power plants. The amounts relating to these obligations cannot be determined because the entities are not able to estimate the final retirement dates for these facilities. In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity from recording an expense for estimated costs associated with the removal or retirement of assets that result from other than legal obligations. The SEC Staff concluded that amounts that are included in accumulated depreciation related to estimated removal costs arising from other than legal obligations should be written off as part of the cumulative effect of adopting SFAS 143 unless the company is regulated under SFAS 71.Companies regulated under SFAS 71 may continue to include removal costs in depreciation rates but must quantify the removal costs included in accumulated depreciation as regulatory liabilities in footnote disclosure. The AEP registrant subsidiaries that are regulated entities have included estimated removal costs for non-legal retirement obligations in book depreciation rates.For non-regulated entities, including certain formerly regulated generation facilities, asset retirement obligations associated with wind farms, closure costs associated with power plants in the U.K. and possibly other items will be incurred.Also the amount of removal costs embedded in accumulated depreciation is expected to result in a favorable cumulative effect adjustment to net income. However, AEP and its registrant subsidiaries have not completed their determination of the net effect of these items on first quarter 2003 results of operations upon the adoption of the provisions of this standard.In August 2001, the FASB issued SFAS 144,"Accounting for the Impairment or Disposal of Long-lived Assets which sets forth the accounting to recognize and measure an impairment loss. This standard replaced, SFAS 121, "Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of. AEP adopted SFAS 144 effective January 1, 2002.The adoption of SFAS 144 did not materially affect AEP s results of operations or financial conditions. See Notes 3 and 13 for discussion of impairments recognized in 2002 by AEP and its registrant subsidiaries, affected by SFAS 144.In April 2002, the FASB issued SFAS 145,"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections'. SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. In 2003, for financial reporting purposes AEP and TCC will reclassify extraordinary losses net of tax on TCC s reacquired debt of $2 million for 2001.In October2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17 (EITF 02-3). EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by generally accepted accounting principles. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts entered into and inventory purchased through October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus will be reported as a cumulative effect of an accounting change. Such contracts and inventory will continue to be accounted for at fair value through December 31,2002. Energycontracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133.L-1 3 Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses.Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows.Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. Unrealized gain or loss at inception is recognized only when the fair value of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts. In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entitys commitment to an exit plan.SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value.The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.In November 2002, the FASB issued Interpretation No. 45, "Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No.34. The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition. See guarantee details discussed in Note 10.In December 2002, the FASB issued SFAS No.148, "Accounting for Stock-Based Compensation-Transition and Disclosure , which amends SFAS No. 123, "Accounting for Stock-Based Compensation .SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Underthe fair value based method, compensation cost for stock options is measured when options are issued. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation. SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options.In November2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation: A Comparison of FASB L-14}}