NOC-AE-31659820, Annual Financial Reports
| ML032970507 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 09/29/2003 |
| From: | Hyde R 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 10CFR50.71 (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 10CFR50.71 (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 10-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 10-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 NOC-AE-31659820 File No.: G20 Page 2 cc:
(paper copy) (electronic copy)
Regional Administrator, Region IV A. H. Gutterman, Esquire U. S. Nuclear Regulatory Commission Morgan, Lewis & Bockius LLP 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011 -8064 L. D. Blaylock City Public Service U. S. Nuclear Regulatory Commission David H. Jaffe Attention: Document Control Desk U. S. Nuclear Regulatory One White Flint North Commission 11555 Rockville Pike Rockville, MD 20852 R. L. Balcom Texas Genco, LP Richard A. Ratliff A. Ramirez Bureau of Radiation Control City of Austin Texas Department of Health 11 00 West 49th Street C. A. Johnson Austin, TX 78756-3189 AEP Texas Central Company Jeffrey Cruz Jon C. Wood U. S. Nuclear Regulatory Commission Matthews & Branscomb P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 F. H. Mallen, w/o N5001 G. Harrison, w/o N5001 R. G. Hyde, w/o N5001 R. D. Piggott, w/o N5014 S. C. Beaver N5014 RMS N2002 File
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2002 - 2001 C h an g&
-Net Income (Loss) (in millions) .
ongoing
' -- - - - ~~$95.7 $1,087-,
as reported'. - S(l19 (519) $971 (153.50 Earnings (Loss) Per Share *- - , -
- ngoing -- .-.. - S89$3.38: -(4~
as reported - 1157] $3.01 (1_2 Revenues billions) o-(in - $14 6 $12.8 -i.
--~Cash Dividends - $2.40 $2.40,
- Year*EndClos~~~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 - 23,4 (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--
adjustment ~~for curring 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 -ofand 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 '-
resructurngplan, 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 - - Qmu.
- r. Writing down the value of poorly difficult for AEP. Due to performing investments contributed to a variety of factors, our earn- charges of approximately $1.5 billion ings fell dramatically, as did our for 2002. Some of these write-offs, stock price. We deeply regret that such as those related to telecommu-our performance was far below our nications assets, were anticipated.
goals and your expectations. Others, such as a $415 million charge related to our generation assets in the In response to the negative United Kingdom, were not. We also developments in 2002, we are taking incurred an equity reduction of nearly decisive steps to strengthen our bal- $600 million because of lost value in ance sheet and put the company back our pension plan assets. While the on track for value growth. We remain latter event lowered the equity on our dedicated to providing low-cost electricity, superior balance sheet, the other items also reduced the earnings customer service and an attractive return to investors. on our income statement.
A look back: Disappointing results On the positive side, despite last year's very tough market, Our utility operations performed reasonably well in we strengthened our balance sheet by $2 billion. We did it 2002 despite rising costs, but the withering of wholesale by selling non-core assets and issuing additional common markets in the U.S. and abroad cut into earnings from stock and equity units. In 2002 we completed the sale of our wholesale operations. As I'm sure you're aware, the SEEBOARD, a regional electric company in the UK, and wholesale arena - including power generation, associated CitiPower, an Australian electricity provider. AEP's first assets and related marketing activity - had been highly visit to the equity market in 20 years occurred last spring.
profitable for us the past couple of years. Cash proceeds of approximately $1.1 billion from thei asset sales and $990 million from the issuance of common AEP's ongoing earnings totaled $2.89 per share in stock and equity units were used to pay down debt.
2002 compared with $3.38 in 2001. As-reported earnings were negative $1.57 per share, down from $3.01 the We did not attain our capitalization goal for 2002 of previous year. 45 percent equity and 55 percent debt but we expect to-
make significant progress this year. 2002 Sharehbolder Return executive management will not be paid 0
Our long-term goal is 50 percent to 55 this year. In addition, we expect to pare our percent debt. -5 capital expenditures forecast for this year by
.,i,:to $200 million, to $1.5 billion.
A look ahead: Focus on the basics *-15:
In 2003, we will focus on the basics. We
- O decision to recommend a reduction in Our are returning to a more traditional model of a regulated utility with a small commercial I.; ......... -25 E:
the quarterly dividend of about 40 percent to our Board of Directors came after consid-group dedicated to maximizing the value of our generation fleet, which is the largest in
. I -30 erable analysis andw as painful but neces-sary. Reducing the dividend to a quarterly the United States. rate of 35 cents per share, starting with the
.40 :
J, 0Vsecond quarter, will result imannual cash S&P Electric AEP Currently, we think AEPs traditional utility Utlity Index S&P lndex ;savings of $340 million. This will imrnmedi-business perform at roughly the same 1will ............... ............. ately improve retained earnings and create level as last year and the wholesale business will have a free cash flow to boost liquidity and pay down debt. We somewhat weaker year. We project 2003 ongoing earnings believe the dividend will still have significant value and in the range of $2.20 to $2.40 per share, including the produce an attractive yield.
dilution from additional equity issued in this year's cE: first quarter. We began shedding assets to improve our balance sheet CL last year and anticipate that process will accelerate in--
To bolster our balance sheet, we plan to lower costs, 2003. Non-core assets are the most likely candidates for E
-c ..reduce the quarterly dividend, dispose of additional non- divestment. This will be an orderly disposition. Proceeds-
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core assets, maintain our liquidity and current lines of will go toward debt reduction. - - - -
-E credit,'and maximize cash flow.
Our liquidity position is strong. We have $3.5 billion CA:
A company-wide cost reduction program should result in available in cash and credit facilities, and we had $1.2 oE0--
o sustainable net savings in operations and maintenance billion in cash at the, end of last year. During 2003, we a
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- . costs of approximately $60 millhon when compared with expect free cash flow of approximately $130 million after
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-i i~ E. . .. .. .. .. -i .E 2002 actual expenditures, and more than $300 million dividends are paid.- -
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tures. We reduced our work force by approximately 1,300 In 2003, we aim for year-end capitalization consistent positions. Based on 2002 performance, bonuses for senior with a strong&BBB rating. We will continue to seek
opportunities for further debt reduction and to work 11-state service territory, thanks in part to increased usage with the rating agencies to ensure we're addressing by residential customers.
their concerns.:.:
AEP's Texas operations were a major contributor to last With deregulation at a standstill in much of our service year's utility-related earnings improvement. Customer ::`
area,.we are re-evaluating our corporate separation choice was introduced in January 2002 in most-areas of initiative. The legal separation of our regulated and our Texas service territory. AEP's obligation to supply .
unregulated businesses is provided for in Texas and Ohio,_ retail electric providers (REPs) in that state last year con-where generation is deregulated and customers in most tributed $495 million to gross margin. Sale of our affiliat-areas are able to choose their electricity supplier. ed REPs to Centrica, a leading retail energy provider, However, the cost savings and benefits for all customers near the end of 2002 provided immediate cash proceeds of:
of a company-wide separation are now uncertain. We are $146 million. The transaction includes an arrangement exploring these issues with our regulators. Our intent is through 2006 that allows AEP. to share in any increased to comply'with restructuring legislation in the states that earnings opportunities that develop in the Texas retail provide for a legal separation and to maintain a functional: *market, protecting us against downside exposure.
separation elsewhere.--
w Transmission represents a significant piece of our Even with deregulation stalled, many of the nearly 5 mil- regulated business. AEP, following Federal Energy
lion customers linked to our Wires will benefit from rate Regulatory Commission (FERC) guidance, continues freezes in their respective states for the next severlS years.: working toward transferring functional control of its 38,000-mile transmission network to regioa transmis-Utility operations: Stable, predictable sion organizations, or RTOs. - .-
AEPs regulated operations generate stable, reasonably predictable revenue and earnings. They have been a You may recall that AEP was among the companies steady contributor to our performance all along. The deeply involved in recent years in developing a proposed mission of our regulated business unit is to provide safe,: for-profit RTO called the Alliance. Last spring, however, 3 cost-effective and reliable service to customers. FERC turned down our proposal, so we are pursuing affil-lation with PJM Interconnection for our eastern assets and Ongoing earnings from utility operations in 2002 totaled the Midwest Independent System Operator in the west, '
$326 per, share, up from $39in 2001. Retail gross - At this point, we don't anticipate divesting our transmis-.
margins rose $250 million in Texas, $178 million in Ohio sion assets. We project RTO-related costs of $30 million i.
and $91 million in other jurisdictions throughout AP's to $40 million in 2003.
Wholesale investments: Unmet expectations Energy marketing: Asset focus.
Our unregulated operations performed well below our Most of the output of our generating units is committed projections in 2002. AEP's wholesale investments lost to our retail customers. The rest is marketed to other
$45 -million or 13 cents per share. Some of these utilities and wholesale customers.
investments, such as our natural gas and barge-line holdings, contributed positively to earnings, but the Our decision to greatly scale back our energy marketing UK generation we acquired in 2001 - the Fiddler's and trading operations and concentrate on' optimizing Ferry and Ferrybridge plants - posted a $59 million the value of our assets is reducing our risk exposure and operating loss. helping to preserve our creditrratings. Net margins from trading activities declined by'$349 million last year The UK has proved to be a very disappointing and because of our reduced activity and because earnings difficult market. The oversupply conditions worsened from trading in 2001 were exceptionally strong. C as the year progressed, particularly after the British gov-
'ernment decided'to subsidize British Energy. The $415 The outstanding net fair; value of trading contracts has million write-down of UK generation that I mentioned fallen from approximately $450 million to $250 millionA:0
- 1 earlier. stems, from recent analyses showing that UK over the past year. The average duration of our existing:-
power prices won't recover to levels that will support the trading book is year-end 2003 for gas and second-half 0 carrying value of the plants on our books at the original 2004 for power.--0 0
0 purchase price of roughly $1 billion.
0
-c Our risk management group continues to work closely U) 0 As I noted above, we will be looking to divest certain with the trading group to ensure limits are enforced.
a 0.
0 wholesale assets and the UK generation certainly will We reduced value-at-risk limits by 50 percent last year..
be considered. An even greater loss is possible in the S Environmental: Compliance and beyond:::
S UK in 2003. We're evaluating the best way, to reduce U)
N earnings drags and preserve shareholder value in Coal-fired generation remains AEP's mainstay. At the C
0 N this investment.l end of 2002, our generating capacity mix was 69 percent S
coal and lignite, 20 p1ercent natural gas, 8 percent nuclear 0
0.
U EOther unregulated investments not related to our whole- and 3 percent wind, hydro and other.
U S sale business also fired poorly and are candidates for"
'Li i-divestment. Our telecommunications business had a $36.- Use of fossilfEels brings with it environmental expendi-'
S million operating loss. We are actively seeking buyers for tures, but our customer prices remain among the lowest'-`
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this business. in the regions where we operate.:
Our ongoing program to meet federal standards to con- Hagan, head of our shared services organization. Tomr:
trol nitrogen oxide emissions'will cost an estimated ;$1.3 ' succeeded Joe' Vipperman, who retired last year after billion to $2 billion in capital expenditures. more than four decades of dedicated service.
AEP remains a leader in policy discussions and research to Last year was indeed difficult and 2003 also holds address environmnental concerns. . ::many challenges. But I believe the measures I have outlined will improve our performance, and we are We are actively promoting enactment of legislation to 4 . C'committed to doing what it takes to rebuild the value further reduce sulfur dioxide, nitrogen oxide and mercury of your investment.
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:: E.Lin n Draper, Jr..
participating in a project, led by Battelle to assess Chairm~an, President &Chief Executive Officer
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whether deep injection of carbon dioxide into the earth February 28, 2003 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:
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AEP's strength, and our employees are our strongest :
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assets. Their dedication, talent and continued commit-0
-ment to our business mission are at the heart of our plan'
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Stepping up to new duties last 'yearwere Holly, Koep -
who was named to oversee our unregulated businesses:
after the departure of Eric van der Walde; nd To m. .......
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
.... ....... d.. .. .............. ............... . . . . ..... . . . . . .. . q . . .
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 _______
TotalI . ... 341 1 __ _
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Full disclosure 'of all Capitalization Ratio 2002 2001 o fina~ncial information o
is included in the. .
'1 Long-Term De b-t ~~~~~~~~~~~~~~0.7% . 0.7%
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%:
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Revenues Expenses:
2002 S14,55 I 2001.
$12,767 f % Change:
Fuel and Purchased Eniergy -,6,307 4,944 Mainitenianceand Other Operation :. .. .:::~~::~: 3,710:
Non-Recoverable Merger Costs':, .: 10 21
~~~~~~~~~~~............. ................ ..... ......
7 B67~~~~~~~~. .-
Asset Impairments :;
Depreciation and Amortization . 1,377 ~ 1,243 Taxes Othe r Than Income Taxes *718: 667: 1.7 Total Expenses 13,292 10,585 Other.Income . ..
445K! 335 Investment Value and Other.Imnpairment Losses 321 -
N.m Other Expenses...... 321 j 187
.1,66. 2 2,330 Income Before Interest, Preferred Dividends. Minority Interest and Income Taxes F
Interest, Preferred Dividends and Minority Interest 831; 867; Income Taxes 214 ~546 Income Before Discontinued Oprtin, xraordinary items and Cumulative Effect 21 917 Discontinued Operations - Income (Loss) (net of tax) (190) ~86.
Extraordinary Losses (net of tax):.:
S Discontinu'ance of Regulatory Accounting for Generation 1 (48):
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Loss on Reacquired Debt:- (2)
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Cumulative Effect of Accounting Change (net of tax)
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Net Income (Loss) S (~1)I $ 971 -u 0
Average Number of Shares Outstanding.. S M
Earnings Per Share: ~.. ..... i3~~: 322 0 0
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Income Before Discontinued Opraions, .~~~~~~~~~~~~~~~~~~~~~~~....... C.
Extraordinary Items and Cumulative Effect.. 2 85:
Discontinued Operationrs. 0:i.26
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Extraordinary Losses: 1.~:: .: ,w (0.16)
.0 CumulIat ive Effect C,)
Net Income (Loss) I (¶.57r $ 3.01 Z)
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Cash Dividends Paid Per Sha're7::- 2.4c~
S $ .40... 0.
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Operating Activities - :
. ;NtIcmNet Ls):fIncome ; ....::! (Loss) ..................
Plus: Discontinued Operations Loss (income)
.. ............... ........ . . . . . . . . . .. . .. . . .. . . .. . . 591 M.
- 0t t:,]"jft'. N Net Income from Continuing Operations sT;eq; fsi:48-Depreciation and Amortization' -.. .: : Tw7S,
. Asset Impairments Investment Value and Other Impairments ,I
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, ;................ for Other Noncash Items Adjustmrents
.. AjsmnsfrOhrNnahiesa dWrigCptl. Working Capita!l and........................................... I............. ... .wi : (3 Net Cash Flows from Operating Activities
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Investing Activities:.
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Construction Expenditures (1 (usi54
.. .... ....................................................................................... ....... 3;4; Purchase of Gas Pipe Line
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Purchase of UK Generation f...
,.g, X,ffi Purchase of Coal Company: .......... ,......
PurchaseofBargingOperations: . -: F. ;' a@t Purchase of Wind Generation:: .¢
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Proceeds from Sale of Retail Electric Providers .~~~~~~~~~~~~~~.
Proceeds from Sale of Foreign Investments :
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.._D Net Cash Flows used for Investing Activities .
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Issuance ofCommon Stock . :
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- I-ssuance of MinorityInterest Issuance of Equity Unit Senior Notes
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Change in Long-term Debt (net) i^.......... .,,,
I l k i N IN Retirement of Cumulative Preferred Stock~: 1n 0.0 0
- liRetiementof~muitive~refrredtock-T .i;0i,,e.,..........I Change in Short-term Debt (net) fs, i S
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Dividen'rds Paidon Coim'mon Stock .. ..
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Cash and Cash Equivalents from Continuiing Operations Beginning of Period a.0 Cash and.Cas Equivalents fo otnigOeain n fPro isi "
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-:.':Net Increase (Decrease) in Cash: and Cash Equivalents from Discontinued Operations: : .5B - : :-; ' :' a Ul Cash and Cash Equivalents from DisContinued Operations- eginning of Period
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~'E 4 Cash and Cash Equivalents from Discontinued Operations - End of Period._
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.':;e n .i-srr To the Shareholders and Board of Directors:: The'management of American Electric Power Company,:.:
of American Electric Power Company, Inc.:-: Inc., is responsible for the integrity, representations and We have audited the consolidated balance sheets of::: objectivity of the information in the Company's sumrmary American Electric Power Company, Inc.,,and its subsidiaries annual report and condensed consolidated financial state-as of December 31, 2002 and 2001, and the related consoli- ments. The condensed consolidated financial statements are dated statements of operations, common shareholders' derived from the consolidated financial statements included
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equity and comprehensive income, and cash flows for each ..in Appendix A to the proxy statement, which has been of the three years in the period ended December 31, 2002. - prepared in conformity with generally accepted accounting These consolidated financial statements and our' report *principles, using informed estimates where appropriate, thereon dated February 21, 2003, expressing an unqualified to reflect the Company's financial condition and results opinion (which are not included herein) are included in.. .::: of operations. The information in other sections of this
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Appendix A to the proxy statement for the 2002 annual summary annual report is consistent with these statements. meeting of.shareholders. The accompanying condensed have been consolidated financial statements .T:::he
~~~~~~~~~~~~~~~~~~~~~... ....
consolidated financial statements are the responsibility audited by Deloitte &Touche LLP, from which these of the Company's management. Our responsibility is to condensed consolidated financial statements have been express an opinion on such condensed consolidated financial derived and whose report appears on this page. The statents in relation to the complete consolidad -. * .> statements in relation to the complete consolidated ;-: S 'auditors provide an objective, independent review as to financial statements. a. management's discharge of its responsibilities insofar as B U In our opinion, the information set forth in the accom-: they relate to the fairness of the Company's reported
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panying condensed consolidated balance sheets as of inancial condition and results of operations. Their audit 7. December 31, 2002 and 2001, and the related condensed : :, :1 includes procedures believed by them to provide reasonable *-u a consolidated statements of operations and of cash flows fort: ,:assurance that the financial statements are free of material::: B
--.. -~~~~~~~~~~~~~~~~~~~~~~~.....
the years then ended is fairly stated in all material respects misstatement and includes an evaluation of the Company's 0 0 N, in relation to the basic consolidated financial statements-.-'-...:s internal control structure over financial reporting. C from which it has been derived.
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0 Columbus, Ohio Chairman, President & 0. February 21, 2003 Chief Executive Officer .Chief Financial Officer:
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, 7:7 Radian International, LLC.
Austin, Texas (2000) .!N. . -m John P. DesBarres, 63 Investor/Consultante 0 0 Park City, Utah : (997) LH.N.r U, 0. Robert W. Fri 67: Leonard J. Kujawa, 70 Donald G. Smith, 67 Committees of the Board: 0 Visiting Scholar, International Energy Consultant Chairman, President The chairman is listed in (). Resources for the FutureL Atlanta, Georgia:: &Chief Executive Officer, A Audit (Carlton),. M.. Washington, D.C. (1997) D.'- Roanoke Electric Steel Corp. :Directors and Corporate 0 (1995)? Roanoke, Virginia Governance (Hudson),.-.. Dr. Richard L Sandor, 61 (1994) N.?- -: : Executive (Draper), William R. Howell 67 Chairman &Chief Finance (Stunt), Co. Chairman Emeritus, Executive Officer, Linda Gillespie Stuntz, 48 H Human Resources (DesBarres), J.C. Penney Company, Inc. Environmnental Financial. Partner-: N Nuclear Oversight (Sullivan),: Dallas, Texas Products, LLC Stuntz, Davis &Staffier, P.C. Policy (Fri) .0 (2000) .H.P Chcago, Illinois Washington, D.C. (2000)Drf~g (1993) "- ' Dr. Lester A. Hudson, Jr., 63 LU Professor of Business Strategy, Thomas V. Shockley, III, 57 Dr. Kathryn D. Sullivan, 51 Clemson University Vice Chairran: President &Chief 0 Greenville, South Carolina:':: (2000) Executive Officer, (18)A-DJ : : i Center of Science &Industry 0C1 Columbus, Ohio (1997) AN.r
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-Service Corporatior nI::0:; i,0- Senior Vice President, Controller and E. Unn Draper, Jr.: f; -t,; Chief Accounting Officer Chairman, President and Chief Executive Officer . Jeffrey D. Cross
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fi -. . :. Joseph Hamrock f i-D:: :S Henry W. Fayne .- . .: Senior Vice President: - Executive Vice President . General Services :: Thomas M. Hagan - -:00-S't.t Dale E. Heydlauff
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' Michelle S. Kalnas Senior Vice President -
Supiply Chain, ' Richard E. Munczinski Generation -117 ,,' i'- Vice Preside'nt -
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Front row Iet to right: Holly K. Koeppel, Company. Inc. Pollcy, Fiance and:. t:'T-ttT,i E. Irnn Draper, Jr., Thomas M. Hagan, Strategic Planning, and Armando A. Pe a (l} i :000 'l: Susan Tomasky, Bac row lift to right: E. Linn Draper, Jr. ::Assistant Secretary :gE: : Senior Vice President Robert P. Powers, Henry W. Fayne, Chairman, President and - :: if:: Finance and Treasurer
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Thomas V. Shockley, III Chief Executive Offi Melinda S. Ackerman:? Senior Vice President - ' ;'::" Michael W.: Rencheck . - Thomas V. ShocklhDy,Il Human Resources *....:!g:-t,,- Senior Vice President - Vice Chairman: *:.i-:-. :i: [- Technical Services:: m
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.Treasurer Seniomor Vice President - -,.,.-;fX,,,..,404 Regulation and Public Polic icye: :: Scott N. Smith -
Senior Vice President . -. : W Susan Tomasky Vice President, Secnr IA. Christopher Bakken, IIIiiE--T --- and Chief Risk Officer:0 3 and Chief Financial Offic ,,.Senior Vice President .- -' fiSif -ff. -:
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_,_-:,_1_ Annual Meeting - The 96th annual meeting of shareholders Stock Held in Brokerage Account ('Street Name') - When of American Electric Power Company will be held at 9:30 a-m. you purchase stock and it is held for you by your broker, it is listed Wednesday, April 23, 2003, at The Ohio State University's Fawcett with the Company in the broker's name or 'street name.' AEP Center, 2400 Olentangy River Road, Columbus, Ohio. Admission does not know the identity of idivdual shareholders who hold is by ticket only. To obtain a ticket, please note the instructions in their shares in this manner, we simply know that a broker holds the Notice of Annual Meeting mailed to shareholders or call the a certain number of shares which'may be for any number of Company. If you hold your shares through a broker, please bring customers. If you hold your stock in street name, you receive all proof of share ownership as of the record date. dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any Shareholder Inquiries - If you have questions about your account, questions you may have about your account should be directed contact the Company's transfer agent, listed below. You should have to your broker. your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the How to Consolidate Accounts - If you want to consolidate your shareholder's approval or appropriate documents. separate accounts into one account, you should contact the transfer agent to obtain the necessary instructions. When accounts are Transfer Agent &Registrar consolidated, it' may be necessary to reissue the stock certificates. EquiServe Trust Company, N.A. ;;..C X.,. ' --A. f:.. .-.-..... ... E i ! : ; A:. :. (formerly First Chicago Trust Company of New York) How to Eliminate Duplicate Mailings - If you want to maintain P.O. Box 43069 more than one account but eliminate additional mailings of annual Providence, RI 02940-3069 reports, you may do so by contacting the transfer agent, indicating Telephone Response Group: 1-800-328-6955 the names you wish to keep on the mailing list for annual reports Internet address: www.equiserve.com and the names you wish to delete. This will affect only these Hearing Impaired #: TDD: 1-800-952-9245 mailings; dividend checks and proxy materials will continue to be sent to each accountI: IdE i-Internet Access to Your Account - If you are a registered shareholder, you can access your account information through Stock Trading - The Company's common stock is traded princi-the Internet at www.equiserve.com. Information about obtaining pally on the New York Stock Exchange under the ticker symbol. a password is available toll-free at 1-877-843-9327. AER AEP stock has been traded on the NYSE for 54 years. Replacement of Dividend Checks - If you do not receive your Taxes on Dividends -The Company paid $2.40 in cash dividends dividend check within five business days after the dividend'pay- in 2002, all of which' are taxable for federal income tax purposes. ment date, or if your check is lost, destroyed or stolen, you should AEP has paid consecutive quarterly dividends since 1910. notify the transfer agent for a replacement. Shareholder Direct - An array of timely recorded messages. Lost or Stolen Stock Certificates - If your stock certificate about AEP, including dividend and earnings information and is lost, destroyed or stolen, you should notify the transfer agent recent news releases, is available from AEP Shareholder Direct immediately so a 'stop transfer' order can be placed on the at 1-800-551-lAEP (1237) anytime day or night. Hard copies of missing certificate. The transfer agent then will send you the information can be obtained via fax or mail. Requests for annual required documents to obtain a replacement certificate. reports, 10-K's, 10-Q's, Proxy Statements and Summary Annual I Reports should be made through Shareholder Direct. Cd, Address Changes - It is important that we have your current address on file so that you do nor become a lost shareholder. Please Financial Community Inquiries - Institutional investors M contact the transfer agent for address changes fbr both record and or secunities analysts who have questions about the Company; dividend mailing addresses. We also can provide automatic should direct inquiries to Bette Jo Rozsa, 614-716-2840, seasonal address changes. bjrozsa@aep.com, orJulie Sloar, 614-716-2885, jsloat@aep.com; E: individual shareholders should contact Kathleen Kozero, : E. Stock Transfer - Please contact the transfer agent if you 614-716-2819, klkozero@aep.com, or April Dawson, have questions regarding the transfer of stock and related 614-716-2591 addawson aep.com. legal requirements,. - Internet Home Page -Information about AEP, including Li) Dividend Rei'nvestment and Direct Stock Purchase Plan - financial documents, SEC filings, news releases and customer A Dividend Reinvestment and Direct Stock Purchase Plan is avail- service information, is available on the Company's home page,:, able to all investors. It is an' economical and convenient method of on the Internet at www..aep.coml. purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the Annual Report and Proxy Materials - You can receivei: transfer agent... i future annual reports, proxy statements and proxies electronically rather than by mail; if you are'a registered holder, log on to Direct Deposit of Dividends - The Company does offer electronic wvww.econsent.comlaep.- If you hold your shares in street name, deposit of your dividends. Contact the transfer agent for details. contact your broker.-7IEI:Ii;
WA MT NO MN i ME OR I0 So VT NH WY M! NY I MA [A NE CT RI NJ NV UT MD co DE CA KS MO OKDr TN NC AZ NM AR C.. SC F:ti'S . MS AL GA C) N-W LA
- AEP service area I-l,
-; Transmission lines FL More than 42,000 megawatts of electric generating 6,400 miles of natural gas pipeline capacity, including the largest generation fleet in the U.S.- 7,000 rail cars 38,000 circuit miles of transmission lines 1,800.barges and 37 tug boats .
186,000 miles of distribution lines:. Annual coal production capability of 10 million tons z iz , -z 128 billion cubic feet of gas storage e American Electric Power owns and operates more than;' West Virginia. The company's distribution service area: 42,000 megawatts of generating capacity in the United *6covers 197,500 square miles.,
.States and select international markets and is the largest electricity generator in the U.S. AEP is also one of the Outside the United States, AEP holds interests in the United largest electric utilities in the United States, with almost 5 Kingdom, Australia, Brazil, China, Mexico and the Pacific million customrers linked to AEP's electricity transmission Regions bs i C Ohio.
and distribution grid. Those customers are located in 11 states - Arkansas, Indiana, Kentucky, Louisiana, Michigan, .AEP is based in Columbus, Ohio. 4 f 0;> Ohio Oklahoma, Tennessee, Texas, Virginia and
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 experience in the wholesale business. or the Company) is one of the largest investor owned electric public utility holding companies Through our utility operations focus, we intend in the U.S. We provide generation, to be the energy and low cost generation transmission and distribution service to almost provider of choice. We have ample five million retail customers in eleven states generation to meet our customers needs. (Arkansas, Indiana, Kentucky, Louisiana, We have a cost advantage resulting from Michigan, Ohio, Oklahoma, Tennessee, AEP s long tradition of designing, building and Texas, Virginia and West Virginia) through operating efficient power plants and delivery our electric utility operating companies. networks. Our customers continue to show top quartile level of satisfaction. We provide We have a vast portfolio of assets including: safe and reliable sources of energy.
- 38,000 megawatts of generating capacity, the largest complement of Our business provides a vital requirement of generation in the U.S., the majority of our economy and affords an opportunity for a which has asignificant cost advantage fair return to our shareholders. Our business in our market areas provides the opportunity for a predictable
. 4,000 megawatts of generating stream of cash flows and earnings, allowing capacity in the U.K., a countrywhich is us to pay a competitive dividend to investors.
currently experiencing excess generation capacity We are addressing many challenges in our
- 38,000 miles of transmission lines, the unregulated business. We have already backbone of the electric substantially reduced our trading activities.
interconnection grid in the Eastern We have written down the value of several U.S. investments to reflect deterioration in market
- 186,000 miles of distribution lines that conditions. We are evaluating our portfolio support delivery of electricity to our and plan to sell assets that are no longer core customers premises to our business strategy. We are also in a Substantial coal transportation assets discussion with our regulators to determine if (7,000 railcars, 1,800 barges, 37 tug the legal separation of certain operating boats and two coal handling terminals company subsidiaries into regulated and with 20 million tons of annual capacity) unregulated segments can be avoided. We
- 6,400 miles of gas pipelines in believe that the expected benefits from legal Louisiana and Texas with 128 Bcf of separation are no longer compelling.
gas storage facilities Transition rules for Michigan and Virginia do not require legal separation. Deregulation is Business Strategy no longer an expectation in the foreseeable future in the other states where we operate. We plan to focus on utility operations in the U.S. We continue to participate in wholesale Our strategy for the core business of utility electricity and natural gas markets. Weakness operations is to: in these markets after the collapse of Enron . Maintain moderate but steady and other companies caused us to re- earnings growth examine and realign our strategy to direct our
- Maximize value of transmission assets attention to our utility markets. We have and protect our revenue stream in an reduced trading to focus predominantly in RTO membership environment markets where we have assets. We plan to
- Continue process improvement to obtain maximum value for our assets by maintain distribution service quality selling excess output and procuring while, at the same time, further economical energy using commercial enhancing financial performance expertise gained from our extensive
- Optimize generation assets through increased availability and sale of A-2
excess capacity We also focused on: Manage the regulatory process to
- Implementing an enterprise-wide risk maximize retention of earnings management system improvement while providing fair and
- Completing a cost reduction initiative reasonable rates to our customers which we expect to result in sustainable net annual savings of We remain very focused on credit quality and more than $200 million beginning in liquidity as discussed in greater detail later in 2003 this report.
- Eliminating or reducing future capital requirements associated with non-We are committed to continually evaluating core assets the need to reallocate resources to areas with greater potential, to match investments with We have redirected our business strategy by:
our strategy and to pare investments that do
- Scaling back trading activities to focus not produce sufficient return and sustainable principally on supporting our core shareholder value. Any investment assets dispositions could affect future results of
- Selling our Texas retail business operations, cash flows and possibly financial . Proposing the sale of a significant condition. portion of the Texas unregulated generation assets 2002 Overview Outlook for 2003 2002 was a year of rapid and dramatic change for the energy industry, including We remain focused on the fundamental AEP, as the wholesale energy market quickly earnings power of our utility operations, and shrank and many of its participants exited or we are committed to strengthening our significantly limited future trading activity. balance sheet. Our strategy for achieving Investors lost confidence in corporate these goals is well planned:
America and the economy stalled. Investors
- First, we will continue to identify demand for stability, predictable cash flows, opportunities to reduce our operations earnings, and financial strength have replaced and maintenance expense.
their demand for rapid growth.
- Second, we will find opportunities to reduce capital expenditures.
Our wholesale business did not perform well. We had significant losses in options trading in
- Third, management recommended a the first half of the year and new investments 40% reduction in the common stock performed well below our expectations. dividend beginning in the second quarter to a quarterly rate of $0.35 per We focused on financial strength by: share. This will result in annual cash
- Issuing approximately $1 billion in savings of approximately $340 million and should improve our retained common stock and equity units earnings as well as create free cash
. Retiring debt of approximately $3 flow to improve liquidity and pay-down billion through the sale of two foreign outstanding debt.
retail utility companies in the U.K. (SEEBOARD) and Australia
- Fourth, we plan to evaluate and, where appropriate, dispose of non-(CitiPower) core assets. Proceeds from these
- Establishing a cash liquidity reserve of sales will be used to reduce debt.
$1 billion at year-end . Fifth, we will continue to evaluate the potential for issuing additional equity See Financing Activity in Managements to further strengthen our balance Discussion and Analysis of Financial sheet and maintain credit quality.
Condition, Accounting Policies and Other Matters in section M for an overview of all We remain committed to being a low cost changes to capital structure. provider of electricity, to serving our A-3
customers with excellence and to providing an wholesale energy markets and in attractive return to investors. We will telecommunications. In 2002, the Company s therefore focus on producing the best Net Loss was $519 million or a loss of $1.57 possible results from our utility operations per share including the fourth quarter losses, enhanced by a commercial group that losses on sales of SEEBOARD and ensures maximum value from our assets. CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and Although we aim for excellent results from CitiPower that resulted from the adoption of operations there are challenges and certain SFAS 142 (see Note 3). risks. We discuss these matters in detail in the Notes to Financial Statements and in Net Income increased in 2001 to $971 million Management s Discussion and Analysis of or $3.01 per share from $267 million or $0.83 Financial Condition, Accounting Policies and per share in 2000. The increase of $704 Other Matters. We will work diligently to million or $2.18 per share was due to the resolve these matters by finding workable growth of AEP s wholesale marketing solutions that balance the interests of our business, increased revenues and the customers, our employees and our investors. controlling of our operating and maintenance costs in the energy delivery business, and Results of Operations declining capital costs. The effect of 2000 charges for a disallowance of COLI-related In 2002, AEP s principal operating business tax deductions, expenses of the merger with segments and their major activities were: CSW, write-offs related to non-regulated
- Wholesale: investments and restart costs of the Cook o Generation of electricity for Nuclear Plant were all contributing factors to sale to retail and wholesale the increase in 2001 earnings compared to customers 2000. The favorable effect on comparative o Gas pipeline and storage Net Income of these 2000 charges was offset services in part in 2001 by losses from Enron s o Marketing and trading of bankruptcy and extraordinary losses for the electricity, gas, coal and other effects of deregulation and a loss on commodities reacquired debt.
o Coal mining, bulk commodity barging operations and other Our wholesale business has been affected by energy supply related a slowing economy. Wholesale energy businesses margins and energy use by industrial Energy Delivery customers declined in 2002 and 2001. o Domestic electricity trans- Earnings from our wholesale business, which mission includes generation, increased in 2001 largely o Domestic electricity distri- as a result of the successful return to service bution of the Cook Plant in June 2000 and by
- Other Investments acquisitions of HPL and MEMCO.
o Energy Services Our energy delivery business, which consists Net Income of domestic electricity transmission and distribution services, contributed to the Income Before Discontinued Operations, increase in earnings by controlling operating Extraordinary Items and Cumulative Effect and maintenance expenses and by increasing decreased $896 million or 98% to $21 million revenues in 2002 and 2001. in 2002 from $917 million in 2001. The Company recognized impairments on under- Capital costs decreased due primarily to performing assets and recorded losses in interest paid to the IRS in 2000 on a COLI value of $854 million (net of tax) (see Note deduction disallowance and continuing 13). The losses in the fourth quarter 2002 declines in short-term market interest rate were generally caused by the extended conditions since early 2001. decline in domestic and international A-4
Volatility in energy commodities markets has had a major effect on the volume of affects the fair values of all of our open wholesale power marketing especially in the trading and derivative contracts exposing AEP short-term market. to market risk and causing our results of operations to be more volatile. See 'Market The increase in 2002 in wholesale revenues Risks section for a discussion of the policies resulted from a 27% increase in trading and procedures AEP uses to manage its volume associated with Wholesale Electricity exposure to market and other risks from which was offset by a continuing decrease in trading activities. gross margins which began in the fourth quarter of 2001, and an increase in Revenues Increase residential sales as a result of favorable weather conditions in the third quarter 2002. AEP s total revenues increased 14% in 2002 In addition OtherWholesale electric revenues and 15% in 2001. The following table shows increased due to the mid-year 2001 the components of revenues: acquisition of barging and coal mining operations as well as the recognition of For The Year Ended revenues for generation projects completed December 31 2002 2001 2000 for third parties. The increase in 2002 (in millions) WHOLESALE: Wholesale Gas revenues resulted from a full Residential commercial
$ 3,713 2,156 S 3,553 S 3,511 2,328 2,249 year of HPL operations compared to a partial Industrial 1,903 2,388 2,444 year from our acquisition date in July 2001, other Retail offset by a decrease in the results from customers 385 419 414 financial trading and MTM unrealized losses.
Electricity Marketing (net) 2,227 802 1,073 Other Investments revenue decreased in unrealized MTM 2002 due to the elimination of factoring of Income-Electric 136 210 38 other 1,397 632 837 accounts receivable of an unaffiliated utility. Less: Transmission and Distribution Revenues Assigned to Energy Prior to the third quarter of 2002, we recorded Delivery* (3.551) i (3.356) (3.174) and reported upon settlement, sales under wholesale Electric 8.366 6,97 7,392 forward trading contracts as revenues and Gas Marketing (net) 3,021 2,274 310 purchases under forward trading contracts as unrealized MTM Income purchased energy expenses. Effective July 1, (Loss)-Gas (399) 47 132 wholesale Gas 2.622 2.321 442 2002, we reclassified such forward trading TOTAL WHOLESALE 10.988 9.297 7,834 revenues and purchases on a net basis, as DOMESTIC ELECTRICITY permitted by EITF 98-10 (see Note 1). DELIVERY: Transmi ssi on 922 1,029 1,009 Distribution 2.629 2,327 2.165 Kilowatthour sales to industrial customers TOTAL DOMESTIC decreased by 10% in 2002 and by 5% in ELECTRICITY 2001. This decrease was due to the DELIVERY 3.551 3,356 3,174 economic slow down which began in late OTHER INVESTMENTS 16 114 105 2001. Sales to residential customers rose 5% due to weather related demand in 2002. The TOTAL REVENUES S14,5m 11.77
, economic slow down reduced demand and
- Certain revenues in the wholesale business wholesale prices especially in the latter part of include energy delivery revenues due primarily to bundled tariffs that are assignable to the 2001.
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 CSW, certain deferred merger costs were expensed in 2000. The merger costs charged Changes in the components of operating to expense included transaction and transition expenses were as follows: costs not allocable to and recoverable from ratepayers under regulatory commission Inc:rease (Decrease) approved settlement agreements to share net Frtom Previous Year 2002 200. merger savings. As expected, merger costs (in millions) Amourit % Amount % declined in 2001 and 2002 after the merger Fuel and Purchased was consummated. Energy: Electricity $ 959 43.7 S(1,275)(36.7) Gas 404 14.7 2,339 570.5 In 2002 AEP recorded pre-tax impairments of Maintenance and other operation 303 8.2 228 6.5 assets (including Goodwill) and investments Non-recoverable totaling $1.4 billion (consisting of Merger Costs (11) i (52.4) (182) (89.7) Asset Impairments 867 N.M. approximately, $866.6 million related to asset Depreciation and Amortization 134 10.8 152 13.9 impairments, $321.1 million related to Taxes other Than investment value losses, and $238.7 million Income Taxes 51 7.6 (16) (2.3) Total 25.6 51.246 13.3 related to discontinued operations) that reflected downturns in energy trading The increase in Fuel and Purchased Energy markets, projected long-term decreases in expense was primarily attributable to an electricity prices, and other factors. These increase in power generation. Net generation impairments exclude the transitional increased 6% for Eastern plants due to impairment loss from adoption of SFAS142 increased demand for electricity and a (see Note 2). The categories of impairments reduction in planned power plant maintenance included: outages for various plants as compared to 2001. The return to service of the Cook 2002 Pre-Tax Estimated Loss (in millions) Plants two nuclear generating units in June 2000 and December 2000 accounted for the Asset Impairments increase in nuclear generation. The increase Held for sale S 483.1 Asset Impairments in Gas expense was primarily due to a full Held and used 651.4 year of HPL operations compared to a partial Investment value Losses 291.9 year from our acquisition date in July 2001. Total The increase in Maintenance and Other Operation expense in 2002 is primarily due to Additional market deterioration associated recognizing a full years expense for the with our non-core wholesale investments, businesses acquired during 2001 including including our U.K. operations, could have an MEMCO (a barging line), Quaker Coal, two adverse impact on our future results of power plants in the U.K. and HPL. In addition, operations and cash flows. Significant long-increased administrative costs for the term changes in external market conditions implementation of customer choice in Texas could lead to additional write-offs and contributed to the increase. The increase was potential divestitures of our wholesale offset in part by a reduction in trading investments, including, but not limited to, our incentive compensation and the effect of U.K. operations. planned boiler plant maintenance at various plants in 2001 and less refueling outages for The rise in Depreciation and Amortization STP in 2002 than 2001. expense in 2002 resulted from the amortization of Texas generation related Maintenance and Other Operation expense Regulatory Assets that were securitized in rose in 2001 mainly as a result of additional early 2002, businesses acquired in 2001 and traders incentive compensation and accruals additional production plant placed into for severance costs related to corporate service. restructuring. Depreciation and Amortization expense With the consummation of the merger with increased in 2001 primarily as a result of the A-6
commencement of amortization of transition This increase was primarily caused by an generation regulatory assets in the Ohio, increase in equity earnings due to acquisitions Virginia and WestVirginia jurisdictions due to of $63 million and a $73 million gain from the passage of restructuring legislation, the new sale of a generating plant (see Note 1). Other businesses acquired in 2001 and additional Expenses increased by $110 million or 143% investments in Property, Plant and in 2001 due to costs to exit air transportation, Equipment. fiber optic and Datapult businesses (see Note 1). Taxes OtherThan IncomeTaxes increased in 2002 due to a full year of state excise taxes Income Taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in The decrease in total Income Taxes in 2002 Texas partly offset by the effect of Texas one- was due to a decrease in pre-tax book income time 2001 assessments and decreased gross offset by the tax effects of the sale of foreign Texas receipts taxes due to deregulation. operations. Interest. Preferred Stock Dividends, Minority Although pre-tax book income increased Interest considerably in 2001, Income Taxes decreased due to the effect of recording in The decrease in Interest in 2002 was primarily 2000 prior year federal income taxes as a due to a reduction in short-term interest rates result of the disallowance of COLI interest and lower outstanding balances of short-term deductions by the IRS and nondeductible debt and the refinancing of long-term debt at merger related costs in 2000. favorable interest rates offset in part by an increased amount of long-term debt Extraordinary Losses and Cumulative Effect outstanding. The loss for transitional goodwill impairment Interest expense decreased 15% in 2001 due related to SEEBOARD and CitiPower resulted to the effect of interest paid to the IRS on a from the adoption of SFAS 142 (see Notes 2 COLI deduction disallowance in 2000 and and 3) and has been reported as a lower average outstanding short-term debt Cumulative Effect of Accounting Change on balances and a decrease in average short- January 1, 2002. term interest rates. In 2001 we recorded an extraordinary loss of Minority Interest in Finance Subsidiary $48 million net of tax to write-off prepaid Ohio increased substantially in 2002 because the excise taxes stranded by Ohio deregulation. distributions to minority interest were in effect The application of regulatory accounting for for the entire year. In 2001 we issued a generation was discontinued in 2000 for the preferred member interest to finance the Ohio, Virginia and West Virginia jurisdictions acquisition of HPL and paid a preferred return which resulted in the after-tax extraordinary of $13 million to the preferred member loss of $35 million. interest. The minority interest was only in effect during the last four months of 2001. New accounting rules that became effective in 2001 regarding accounting for derivatives Other Income/Other Expenses required us to mark-to-market certain fuel supply contracts that qualify as financial Other Income increased by $110 million or derivatives. The effect of initially adopting the 33% in 2002 due to the sale of AEP S retail new rules at July 1, 2001 was a favorable electric providers in Texas and due to non- earnings effect of $18 million, net of tax, operational revenue (see Note 1). Other which is reported as a Cumulative Effect of Expenses increased $134 million or 72% in Accounting Change. 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) L3.01 $ 0.83 I$(1.5) 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) Accumulated other Common stock Paid-In Retained comprehensive shares Amount Capi tal Earnings Income (Loss) Total DECEMBER 31, 1999 331 $2,149 $2,898 S3,630 $ (4) $8,673 Issuances - 3 11 14 cash Dividends Declared (805) (805) Other 6 (2) 4 7,886 comprehensive Income: Other Comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment (119) (119) Reclassification Adjustment For LOSS Included in Net Income 20 20 Net Income 267 267 Total Comprehensive Income 168 DECEMBER 31, 2000 331 $2,152 S2,915 $3,090 S(103) $8,054 Issuances 1 9 10 cash Dividends Declared (773) (773) other (18) 8 (10) 7,281 comprehensive Income: Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment (14) (14) unrealized Gain (Loss) on Hedged Derivatives (3) (3) Minimum Pension Liability (6) (6) Net Income 971 971 Total Comprehensive Income 948 DECEMBER 31, 2001 331 $2,153 S2,906 $3,296 S(126) $8,229 Issuances 17 108 568 676 cash Dividends Declared (793) (793) Other (61) 15 (4 ) (163) Com prehensive Income: Other comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment 117 117 unrealized Gain (Loss) on Hedged Derivatives (13) (13) Minimum Pension Liability (585) (585) unrealized Loss on securities Available For Sale (2) (2) Net Income (Loss) (519) (519) Total comprehensive Income (1.002) DECEMBER 31, 2002 MA S3.13 1S9M sff) 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 weighted Average Maturity Interest Rate Interest Rates at December 31. December 31. December 31. 2002 2002 2001 2002 2001 (in millions) FIRST MORTGAGE BONDS (a) 2002 -2004 6.87% 6.00%-7.85% 6.00%-7.85% $ 648 S 1,246 2005 -2008 6.90% 6.20%-8% 6.20%-8% 463 699 2022-2025 7.66% 6.875%-8.7% 6-7/8%-8.80% 773 850 INSTALLMENT PURCHASE CONTRACTS (b) 2002-2009 4.62% 3.75%-7.70% 1.80%-7.70% 396 446 2011-2030 5.83% 1.35%-8.20% 1.55%-8.20% 1,284 1,234 NOTES PAYABLE (c) 2002-2021 5.54% 3.732%-9.60% 4.048%-9.60% 520 217 SENIOR UNSECURED NOTES 2002 -2005 5.53% 2.12%-7.45% 2.31%-7.45% 1,834 1,910 2006-2012 5.91% 4.31%-6.91% 6.125%-6.91% 2,295 1,727 2032-2038 6.64% 6.00%-7-3/8% 7.20%-7-3/8% 690 340 JUNIOR DEBENTURES 2025-2038 7.90% 7.60%-8.72% 7.60%-8.72% 205 618 SECURITIZATION BONDS 2003-2016 5.40% 3.54%-6.25% 797 OTHER LONG-TERM DEBT (d) 247 258 Unamortized Discount (net) (32) (40) Total Long-term Debt outstanding 10.120 9, 505 Less Portion Due Within One Year 1 633 1.095 Long-term Portion L 8410 EQUITY UNIT SENIOR NOTES 2007 5.75% 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 S 1,633 2004 824 2005 993 2006 1,611 2007 1,081 Later Years 4.386 10,528 Unamortized Discount 32 Total £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. combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 Goodwill and other Intangible Assets Note 3 Merger Note 4 Nuclear Plant Restart Note 5 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 Impairments and Investment value Losses Note 13 Benefit Plans Note 14 stock-Based compensation Note 15 Business Segments Note 16 Risk Management, Financial Instruments And Derivatives Note 17 Income Taxes Note 18 Basic and Diluted Earnings Per share Note 19 Supplementary Information Note 20 Power and Distribution Projects Note 21 Leases Note 22 Lines of credit and sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Minority Interest in Finance subsidiary Note 26 Equity units Note 27 Subsequent Events (unaudited) 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 inthe 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 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $213,281 $227,548 $228,516 $217,189 $224,146 operating Expenses 207,152 220.571 220,092 211,849 215,415 operating Income 6,129 6,977 8,424 5,340 8,731 Nonoperating Items, Net 3,681 3,484 3,429 3,659 3,364 Interest charges 2,258 2,586 3.869 2.804 3.149 Net Income ,$L52 $ 77875 $ ,94 $6J195 $ Ai December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $652,213 $648,254 $642,302 $640,093 $636,460 Accumulated Depreciation 358.174 337,151 315.566 295.065 277. 855 Net Electric Utility Plant $-3-1-,10 $36,736 ,$345,028 Total Assets $349,729 $361,41 $374,602 A
$403 U892 Common stock and Paid-in capital $ 24,434 $ 24,434 $ 24,434 $ 30,235 $ 36,235 Retained Earnings 18.163 13.76 9,722 3.673 2,770 Total Common shareholder's Equity $ 4259 $ 3-8,19-5 $900 Long-term Debt (a) S_4i8QZ $4,793 $ 44,808 $ 48 44,79 Total Capitalization And Liabilities UAJTZ9 $36 1 ,41 $374,602 $98 4 $4031892 (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 Operating Expenses Decrease generation and wholesale sale of electric power to two affiliates under long-term Operating Expenses decreased 6% as agreements. follows: Increase Operating Revenues are derived from the (Decrease) (dollars in thousands) From Previous Year sale of Rockport Plant energy and capacity to . _ _ . . _ . _ . ., _ _ _ _ _ _ _ _ _ Amount % two affiliated companies, I&M and KPCo, Fuel $(13,723) (13) pursuant to FERC approved long-term unit other operation 1,899 17 power agreements. Under the terms of its Maintenance 565 6 Depreciation 137 1 unit power agreement, l&M will purchase all of Taxes other Than Income AEGCo's Rockport capacity unless it is sold to Taxes (976) (23) Income Taxes (1.321) (46) other utilities. A unit power agreement Total S(3,41) (6) between AEGCo and KPCo expires in 2004. The KPCo unit power agreement extends until The decrease in Fuel expense reflects a December 31, 2009 for Rockport Plant Unit 1 decrease in generation and lower average and until December 7, 2022 for Rockport fuel costs. Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. The unit power agreements Other Operation expense increased due to increased costs for employee benefits and provide for recovery of costs including a property insurance. FERC approved rate of return on common equity and a return on other capital net of The increase in Maintenance expense can be temporary cash investments. Under terms of attributed to shorter duration of maintenance the unit power agreements, AEGCo outages for boiler inspection and repair in accumulates all expenses monthly and 2001. prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and establishes a receivable from the affiliated personal property taxes reflecting a favorable companies. change in the law which lowered the tax for Rockport Plant. Results of Operations The decrease in Income Taxes attributable to Net Income decreased $323,000 or 4% as a operations is primarily due to a decrease in result of limits on recovery of return on capital pre-tax operating income and a change in related to operating and in-service ratios of estimate for state income tax accruals. the Rockport Plant. 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 Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING REVENUES $213.281 $227.548 $228,516 OPERATING EXPENSES: Fuel 89,105 102,828 102,978 Rent - Rockport Plant Unit 2 68,283 68,283 68,283 other operation 12,924 11,025 10,295 Maintenance 9,418 8,853 9,616 Depreciation 22,560 22,423 22,162 Taxes other Than Income Taxes 3,281 4,257 3,854 Income Taxes 1.581 2.902 2.904 TOTAL OPERATING EXPENSES 207,152 220. 571 220.092 OPERATING INCOME 6,129 6,977 8,424 NONOPERATING INCOME 343 30 6 NONOPERATING EXPENSES 198 16 17 NONOPERATING INCOME TAX CREDITS 3,536 3,470 3,440 INTEREST CHARGES 2.258 2.586 3.869 NET INCOME .$ -752 $_zl875 $ 7L984 Statements of Retained Earnings Year Ended December 31. 2002 2001 2000 (in thousands) RETAINED EARNINGS JANUARY 1 $13,761 $ 9,722 $3,673 NET INCOME 7,552 7,875 7,984 CASH DIVIDENDS DECLARED 3 150 3.836 1.935 RETAINED EARNINGS DECEMBER 31 18&-63 $13 ,761 $4X7 See Notes to Financia7 Statements beginning on page L-1. 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 S3A4 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 $ 7,552 S 7,875 $ 7,984 Adjustments for Noncash Items: Depreciation 22,560 22,423 22,162 Deferred Income Taxes (5,028) (6,224) (5,842) Deferred Investment Tax Credits (3,361) (3,414) (3,396) Amortization of Deferred Gain on sale and Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571) Change in Certain Current Assets and Liabilities: Accounts Receivable 4,037 1,224 1,392 Fuel, Materials and supplies (5,450) (4,738) 6,486 Accounts Payable 6,697 (4,597) (13,157) Taxes Accrued (2,450) (216) 708 other Assets (5,211) (569) 1,636 other Liabilities (2.295) (1.244) (404) Net Cash Flows From operating Activities 11,480 4,949 11. 998 INVESTING ACTIVITIES Construction Expenditures (5,298) (6,868) (5,190) FINANCING ACTIVITIES: Return of Capital to Parent Company (5,801) change in short-term Debt (net) (24,700) Change in Advances From Affiliates (net) (4,01-5) 3,981 28,068 Dividends Paid (3,150) (3.836) (1.935) Net Cash Flows From (Used For) Financing Activities (7.165) 145 (4,368) Net Increase (Decrease) in cash and cash Equivalents (983) (1,774) 2,440 Cash and cash Equivalents January 1 983 2,757 317 cash and cash Equivalents December 31 $~ _ $ 98 supplemental Disclosure: Cash Paid for interest net of capitalized amounts was $2,019,000, $1,509,000 and $3,531,000 and for income taxes was $7,884,000, $8,597,000 and $6,820,000 in 2002, 2001 and 2000, respectively. 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. combined Footnote Reference significant Accounting Policies Note 1 Effects of Regulation Note 7 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 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 Related Party Transactions 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 SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $1,690,493 $1,738,837 $1,770,402 $1,482,475 $1,406,117 Operating Expenses 1.296.760 1,443.106 1.463.304 1.188.490 1 123.330 Operating Income 393,733 295,731 307,098 293,985 282, 787 Nonoperating Items, Net 8,079 5,324 7,235 8,113 760 Interest charges 125.871 116.268 124,766 114 380 122.036 Income Before Extraordinary Item 275,941 184,787 189,567 187,718 161,511 Extraordinary Loss (2.509) (5 517) Net Income 275,941 182,278 189,567 182,201 161,511 Preferred stock Dividend Requirements 241 242 241 6,931 6,901 Gain (Loss) on Reacquired Preferred Stock 4 (2.763) Earnings Applicable To Common stock $_275704 1$_182L 06 $ 172.507 L$_ 15-461Q Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,625,736 $5,769,707 $5,592,444 $5,511,894 $5,336,191 Accumulated Depreciation And Amortization 2.405.492 2.446.027 2.297,189 2.247,225 2.072.686 Net Electric Utility Plant $320 -244 Total Assets $5'536P438 $4,735,_ff Common stock and Paid-in capital $ 187,898 $ 573,903 $ 573,904 $ 573,904 $ 573,904 Accumulated other comprehensive Income (Loss) (73,160) Retained Earnings 986.396 826,197 792,219 758.894 734. 387 Total Common shareholder's Equity
$1- 1O1t 13A $1,420QlQQ -$-I33-,79
$1 1QWLZX Preferred stock $ 5,942- $ 5,951 $5.95 CPL Obli ated, Mandatori 1y Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior subordinated Debentures of CPL
$-13-6 Z5- SI136 25Q $148,500 Long-term Debt (a) $1,454,559 $154,5I41 Total capitalization And Liabilities $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 implementation of REPs as suppliers to retail known as Central Power and Light Company customers has caused a significant shift in (CPL), is a public utility engaged in the TCC s sales as described below under generation, purchase, sale, transmission and "Results of Operations. distribution of electric power in southern Texas. TCC also sells electric power at In December 2002, AEP sold the affiliated wholesale to other utilities, municipalities, REP to an unrelated third party who assumed rural electric cooperatives and beginning in the obligations of the affiliated REP under the 2002 to its affiliated retail electric provider Texas Restructuring Legislation (see Note (REP) in Texas. 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Wholesale power marketing activities are Affiliates. Subsequent to the sale, conducted on TCC s behalf byAEPSC. TCC, transactions with the REP were classified as along with the other AEP electric operating Wholesale Electricity or Energy Delivery. subsidiaries, shares in AEP s electric power transactions with other utility systems and Results of Operations power marketers. In 2002, Net Income increased $94 million or 51 % primarily due to $262 million of revenues On January 1, 2002, customer choice of associated with recognition of stranded costs electricity supplier began in the Electric in Texas offset in part by losses associated Reliability Council of Texas (ERCOT) area of with the commencement of customer choice Texas where TCC operates. in Texas which resulted in the loss of customers and reduced prices (see Note 8). Under the Texas Restructuring Legislation, In 2001, Income Before Extraordinary Item each electric utility was required to submit a decreased $5 million or 3%, primarily resulting plan to structurally unbundle its business into from a settlement of Texas municipal an affiliated REP, a power generator, and a franchise fees and increased Maintenance transmission and distribution utility. During expenses. the year 2000, TCC submitted a plan for separation that was subsequently approved Changes in Operating Revenues by the PUCT. TCC has functionally separated its generation from its transmission and Increase (Decrease) From Previ ous Year distribution operations and AEP formed a (dollars in millions) separate affiliated REP. Pending regulatory 2002 2001 Amount % Amount approval, TCC anticipates legally separating whol esal e its generation from its transmission and El ectri ci ty* S(1, 096.4) (90) S(29.9) (2) distribution operations (see Note 8). The Energy Delivery* 81.4 17 (5.6) (1) affiliated REP, aseparate legal entitythatwas Sales to AEP an AEP subsidiary (not owned by or Affiliates 966.7 N.M. 4.0 11 Total 5(8.) (3) 5 31. 5) (2) consolidated with TCC) was sold in December 2002 (see Note 12). *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy Since the affiliated REP is the electricity delivery. supplier to retail customers in the ERCOT N.M. = Not Meaningful area, TCC sells its generation to the affiliated REP and other market participants and In 2002, Wholesale Electricity revenues provides transmission and distribution decreased as a result of the elimination of services to retail customers of the REPs inthe TCCs retail electricity sales in the ERCOT TCC service territory. As a result of the region as of January 1,2002 and a decrease formation of the affiliated REP, effective in wholesale power marketing margins offset January 1, 2002, TCC no longer supplies in part by the interchange cost reconstruction electricity directly to retail customers. The C-2
(ICR) adjustments (see Note 6). In 2001, the based on the current spot market price. decrease in Wholesale Electricity revenues Changes in natural gas prices affect TCC s was primarily attributable to unfavorable fuel expense; however, they generally did not wholesale power marketing and trading impact results of operations in 2001 and 2000 conditions. due to fuel recovery mechanisms, which are no longer in place beginning with deregulation In 2002, Sales to AEP Affiliates revenue in 2002. increased primarily due to increased revenues from the newly created affiliated REP. In 2002, the increase in Wholesale Electricity Although TCC sold electricity to the affiliated Purchased Power expense is due to higher REP instead of directly to retail customers, MWH purchases from the market where we total revenues decreased due to lower prices could purchase power at prices lowerthan our cost to produce. ICR adjustments also had for power sold to the affiliated REP. the effect of increasing Wholesale Electricity Purchased Power expense and decreasing Additionally, delivery charges provided to the AEP Affiliates Purchased Power expense in affiliated REP in 2002 are classified as Sales 2002 (see Note 6). to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery In 2001, Purchased Power increased overall revenue. Revenues for 2002 included $262 largely due to higher natural gas prices. million of revenues, associated with Although gas prices declined in 2001, they recognition of stranded costs in Texas (see were higher during the first half of 2001 when Note 8). Energy Delivery revenue also TCC was making most of its purchases. included revenues received for securitized assets beginning in 2002 (see Note 8). In2002, Other Operation expense decreased due primarily to the elimination of factoring of Chances in Operatinc ExDenses accounts receivable and lower ERCOT Increase (Decrease) transmission related expenses. From Previous Year (dollars in millions) In 2002, Maintenance expense decreased 2002 2001 due to two scheduled '18 month interval Amount % Amount % refueling outages for STP during 2001 that increased Maintenance expense above the Fuel V(:246.2) (50) SC58.8) C11) 2002 and 2000 levels. Also contributing to Purchased Power: the decrease in 2002, and the increase in wholesale Electricity 83.5 65 C16.2) (11) 2001, was an increase in Maintenance AEP 83.5* 65 (16.2) (l ) expense for scheduled major overhauls of Affiliates (35.3) (60) 26.0 80 four power plants in 2001. other operation (17.1) (5) 1-1 1.7
- I -
1 Maintenance tO'.i.) L.+/-+/-J +/-U. I IO In 2002, the increase in Depreciation and Depreci ati on And Amortization is attributable to the amortization Amortization 45.8 27 (10.4) (6) of regulatory assets that were securitized in Taxes other Than Income Taxes 4.6 5 14.4 19 the first quarter of 2002, offset by the Income Taxes 26.1 23 12.4 12 elimination of excess earnings expense in Total la .46) (10) -A) C') 2002 under Texas Restructuring Legislation (see Note 8). In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of In 2002, the increase in Taxes Other Than fuel and decreased generation. The Income Taxes resulted primarily from higher decrease in Fuel expense in 2001 was local franchise taxes, offset by one-time 2001 primarily due to a reduction in the average assessments and decreased gross receipts cost of fuel primarily from a decline in natural tax, due to deregulation. In 2001, Taxes gas prices. TCC used natural gas as fuel for Other Than Income Taxes increased due 32% of its generation in 2002. The nature of primarily to an increase in franchise related the natural gas market is such that both long- taxes, including a settlement of disputed term and short-term contracts are generally franchise fees, and a new tax levied by the C-3
PUCT, the Texas System Benefit Fund current cost to generate electricity, TCC Assessment. proposed in September 2002 to "inactivate various, high-cost gas fired generating In 2002, the increase in Income Taxes is due facilities. In the third quarter 2002, TCC to an increase in pre-tax income offset by recorded an impairment charge of changes in timing between book/tax approximately $95.6 million (pre-tax) related accounting differences in state income taxes. to these plants and recorded approximately In 2001 the increase in Income Tax expense $4.0 million (pre-tax) for severance charges. is primarily due to adjustments associated Both of these charges were deferred and with prior year tax returns and an increase in recorded in RegulatoryAssets Designated for pre-tax book income. or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up Other Changes proceeding (see Note 8). Inthe fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional In 2002, Nonoperating Income and plant impairments, fuel inventory and Nonoperating Expenses increased materials and supplies, and an additional $1.5 significantly as a result of increased non-utility million pre-tax charge was recorded related to revenue and expenses associated with severance charges (see Note 13) related to energy related construction projects for third the Inactivated plants. The entire $23.1 parties, offset in part by decreased interest million was also deferred and recorded in income. The revenues associated with the Regulatory Assets Designated for or Subject energy related construction projects included to Securitization. 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. 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). In2001, 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 $ 127,502 $1,223,893 $1,253,836 Energy Delivery 554,547 473,182 478,814 Sales to AEP Affiliates 1.008.444 41.762 37.752 TOTAL OPERATING REVENUES 1.690.493 1. 738. 837 1.770.402 OPERATING EXPENSES: Fuel 245,834 492,057 550,903 Purchased Power: wholesale Electricity 211,358 127,816 144,021 AEP Affiliates 23,406 58,641 32,591 other operation 304,094 321,227 319,539 Maintenance 63,392 71,212 60,528 Depreciation and Amortization 214,162 168,341 178,786 Taxes other Than Income Taxes 95,500 90,916 76,477 Income Taxes 139.014 112.896 100.459 TOTAL OPERATING EXPENSES 1. 296, 760 1.443.106 1.463. 304 OPERATING INCOME 393,733 295,731 307,098 NONOPERATING INCOME 53,141 22,552 5,830 NONOPERATING EXPENSES 41,910 17,626 3,668 NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,152 (398) (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) (2.509) NET INCOME 275,941 182,278 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS 241 242 241 GAIN ON REACQUIRED PREFERRED STOCK 4 EARNINGS APPLICABLE TO COMMON STOCK $ -18Z-16 Consolidated Statements of Comprehensive Income Year Ended December 31. 2002 2001 2000 (in thousands) NET INCOME $275,941 $182,278 $189,567 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (36) Minimum Pension Liability (73,124) COMPREHENSIVE INCOME $182-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 $ 266197 $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 $2,903,942 $3,169,421 Transmission 698,964 663,655 Distribution 1,296,731 1,279,037 General 258,386 241,137 Construction work in Progress 200,947 169,075 Nuclear Fuel 266.766 Total Electric Utility Plant 5,625,736 5,769,707 Accumulated Depreciation and Amortization 2.405.492 2.446,027 NET ELECTRIC UTILITY PLANT 3.220.244 3. 323.680 OTHER PROPERTY AND INVESTMENTS 3.977 47,950 SECURITIZED TRANSITION ASSETS 734. 591 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4.392 28 039 CURRENT ASSETS: Cash and Cash Equivalents 85,420 10,909 Accounts Receivable: General 113,543 38,459 Affiliated companies 121,324 6,249 Allowance for uncollectible Accounts (346) (186) Fuel Inventory 32,563 38,690 Materials and supplies 51,593 55,475 Accrued Utility Revenues 27,150 Energy Trading and Derivative Contracts 22,493 34,480 Prepayments and other current Assets 2.133 2.742 TOTAL CURRENT ASSETS 455.873 186 818 REGULATORY ASSETS 458. 552 226. 812 REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 336.444 959,294 NUCLEAR DECOMMISSIONING TRUST FUND 98.474 98.600 DEFERRED CHARGES 43,891 21.837 TOTAL ASSETS Sig56E438 $4,9303 See Notes to Financial Statements beginning on page L-1. 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 $ 55,292 $ 168,888 Paid-in Capital 132,606 405,015 Accumulated other comprehensive Income (Loss) (73,160) Retained Earnings 986 396 826.197 Total Common shareholder s Equity 1,101,134 1,400,100 Preferred stock 5,942 5,952 CPL obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of CPL 136,250 136,250 Long-term Debt 1,209.434 988.768 TOTAL CAPITALIZATION 2.452.760 2,531.070 OTHER NONCURRENT LIABILITIES 74.572 10.905 CURRENT LIABILITIES: short-term Debt Affiliates 650,000 Long-term Debt Due within one Year 229,131 265,000 Advances from Affiliates (net) 126,711 354,277 Accounts Payable General 72,199 65,307 Accounts Payable Affiliated Companies 36,242 49,301 customer Deposits 666 26,744 Taxes Accrued 24,791 83,512 Interest Accrued 51,205 23,715 Energy Trading and Derivative Contracts 19,811 40,987 other 36. 698 18,076 TOTAL CURRENT LIABILITIES 1.247.454 926.919 DEFERRED INCOME TAXES 1.261.252 1,163.795 DEFERRED INVESTMENT TAX CREDITS 117.686 122.892 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,713 17,675 REGULATORY LIABILITIES AND DEFERRED CREDITS 201.001 119.774 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES S5,356A438 $41 9,83A3D See Notes to Financia7 statements beginning on page L-1. C-8
- - l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.
2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $275,941 $182,278 $189,567 Adjustments to Reconcile Net Income to Net cash Flows from Operating Activities: Depreciation and Amortization 214,162 168,341 178,786 Extraordinary Loss on Reacquired Debt 2,509 Deferred Income Taxes 113,655 (72,568) 16,263 Deferred Investment Tax credits (5,206) (5,208) (5,207) Mark-toMarket Energy Trading and Derivative Contracts (1,558) (12,048) 8,191 change in Certain Current Assets and Liabilities: Accounts Receivable (net) (189,999) 52,862 (32,902) Fuel, Materials and supplies (4,899) (18,215) 8,680 Interest Accrued 27,490 (2,502) 11,494 Accrued Utility Revenues (27,150) Accounts Payable (6,167) (55, 311) 45,873 Taxes Accrued (58,721) 27,986 14,405 Fuel Recovery 16,455 179,866 (96,872) Transmission coordination Agreement settlement 15,519 Texas wholesale Clawback (see Note 7) (262,000) change in other Assets (534) 10,767 589 Change in other Liabilities 56.024 11,163 12 .243 Net cash Flows From Operating Activities 147.493 469,920 366,629 INVESTING ACTIVITIES: Construction Expenditures (151,645) (193,732) (199,484) Proceeds From Sales of Property and other 143 (354) Net cash Flows used For Investing Activities (151. 502) (194.086) (199.484) FINANCING ACTIVITIES: Issuance of Long-term Debt 797,335 260,162 149,248 change in short-term Debt Affiliate (Net) 650,000 Retirement of Common stock (386,005) Retirement of Preferred stock (6) Retirement of Long-term Debt (639,492) (475,606) (151,440) change in Advances from Affiliates (net) (227,566) 84,565 (52,446) special Deposit for Reacquisition of Long-term Debt 50,000 Dividends Paid on Common stock (115, 505) (148,057) (156,000) Dividends Paid on Cumulative Preferred Stock (241) (242) (249) Net cash Flows From (used For) Financing Activities 78.520 (279,178) (160.887) Net Increase (Decrease) in Cash and Cash Equivalents 74,511 (3,344) 6,258 Cash and Cash Equivalents January 1 10.8909 14.253 7.995 Cash and cash Equivalents December 31 SLQ 3Q9 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) COMMON SHAREHOLDER S EQUITY (a) S1.10o.134 S1.400.100 PREFERRED STOCK 3,035,000 authorized shares, 5100 par value Not Subject to Mandatory Redemption: call Price - Shares December 31, Number of shares Redeemed outstanding series 2002 Year Ended December 31. Dec:ember 31. 2002 2002 2001 2000 4.00% S105.75 100 - - 41,938 4,194 4,204 4.20% 103.75 - - - 17,476 1.748 1,748 Total Preferred stock 5.942 5.952 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 136.250 136. 2 50 LONG-TERM (See schedule of Long-term Debt): First Mortgage Bonds 152,353 614,200 Securitization Bonds (a) 796,635 Installment Purchase Contracts 489, 577 489,568 Senior unsecured Notes - 150,000 Less Portion Due within One year (229.131) (265.000) Long-term Debt Excluding Portion Due within one Year 1.209.434 988. 768 TOTAL CAPITALIZATION (a) In February 2002, TCC issued securitization bonds. S386 million of the proceeds was used to retire 4,543,857 shares of common stock. See Notes to Financial Statements beginning on page L-1. C-1 0
i - AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as December 31, follows: 2002 2001 December 31. (in thousands) 2002 2001 % Rate Due (in thousands) Matagorda County
% Rate Due Navigation District, 7.25 2004 October 1 S 27,400 $100,000 Texas:
7.50 2002 December 1 115,000 6.00 2028 July 1 $120,265 S120,265 6-7/8 2003 February 1 16,418 49,200 6-1/8 2030 May 1 60,000 60,000 7-1/8 2008 February 1 18,581 75,000 3.75 2030(a) May 1 111,700 111,700 7.50 2023 April 1 17,996 75,000 4.00 2030(a) May 1 50,000 50,000 6-5/8 2005 July 1 71. 958 200 000 4.55 2029(a) Nov . 100,635 100,635 Total ikQu Q Guadalupe-Blanco River Authority First mortgage bonds are secured by a first District, Texas: mortgage lien on electric utility plant. The (b) 2015 November 1 40,890 40,890 indenture, as supplemented, relating to the Red River Authority first mortgage bonds contains maintenance District, Texas: 6.00 2020 June 1 6,330 6,330 and replacement provisions requiring the unamortized Discount (243) (252) deposit of cash or bonds with the trustee, or in Total S4O9,577 lieu thereof, certification of unfunded property (a)installment Purchase contract provides for bonds to be tendered in 2003 for 3.75% and additions. 4.00% series and in 2006 for 4.55% series. Therefore, these installment purchase contracts have been classified for payments in Securitization Bonds outstanding were as those years. follows: (b) A floating interest rate is determined monthly. The rate on December 31, 2002 was 1.7%. December 31. Final 2002 2001 Under the terms of the installment purchase Payment Maturity (i~nthousands) contracts, TCC is required to pay amounts Rate Date Date 3.54 1/15/2005 1/15/2007 S128,950 $ sufficient to enable the payment of interest on 5.01 1/15/2008 5.56 1/15/2010 1/15/2010 1/15/2012 154,507 107,094 and the principal (at stated maturities and 5.96 7/15/2013 7/15/2015 214,927 upon mandatory redemptions) of related 6.25 1/15/2016 1/15/2017 191,857 pollution control revenue bonds issued to unamortized Discount (700) Total 5796>6i5 finance the construction of pollution control facilities at certain plants. In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, Senior unsecured notes outstanding were as issued $797 million of Securitization Bonds, follows: Series 2002-1. The Securitization Bonds December 31. mature at different times through 2017 and 2002 2001 (in thousands) have a weighted average interest rate of 5.4 % Rate Due percent. 2002 February 22 Cc) $ - S150.000 Total S - $150.AlOO Installment purchase contracts have been (c) A floating interest rate is determined entered into in connection with the issuance monthly. 2.56%. The rate on December 31, 2001 was of pollution control revenue bonds by governmental authorities as follows: C-11
At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) 2003 S 229,131 2004 75,951 2005 121,937 2006 152,900 2007 52,729 Later Years 806.860 Total Principal Amount 1,439,508 unamortized Discount (943) Total 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. 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 Impairment 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 Trust Preferred Securities Note 25 Jointly owned Electric utility Plant Note 28 Related Party Transactions 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 Year Ended December 31 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 450,740 $556,458 $571,064 $445,709 $424,953 operating Expenses 442.869 523.068 518.723 391.910 365,677 operating Income 7,871 33,390 52,341 53,799 59,276 Nonoperating Items, Net (703) 2,195 (1,675) 2,488 2,712 Interest charges 20,6845 23, 275 23,216 24,420 24.263 Income (Loss) Before Extraordinary Item (13,677) 12,310 27,450 31,867 37,725 Extraordinary Loss (5.461) Net Income (Loss) (13,677) 12,310 27,450 26,406 37,725 Preferred stock Dividend Requirements 104 104 104 104 104 Earnings (Loss) Applicable to Common stock $ (13.781) S 34-6 S 26,302 $ 37,621 December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,201,747 $1,260,872 $1,229,339 $1,182,544 $1,146,582 Accumulated Depreciation and Amortization 521.792 546,162 515,041 495.847 473.503 Net Electric utility Plant S 679,955 $ 714,710 $ 714,298 5 686,697 $ 673,079 Total Assets $ 877,175 51,087. 504 $ 861,205 $,819,446 Common stock and Paid-in Capital $ 139,565 $ 139,565 $ 139,565 $ 139,565 S 139,565 Accumulated other Comprehensive Income (LosS) (30,763) Retained Earnings 71.942 105.970 122,588 113,242 114.940 Total Common Shareholder's Equity $1&80,744 $_241S53-5 $_262 153 S_252 s807 S 254,505 Cumulative Preferred stock: Not subject to Mandatory Redemption S 2,367 255.7 $S_22 _N S 68 Long-term Debt (a) $ 132,50 S 255,967 Total Capitalization And Liabilities S 877L21Z5 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 TNC service territory. As a result of the known as West Texas Utilities Company formation of the affiliated REP, effective (WTU), is a public utility engaged in the January 1, 2002, TNC no longer supplies generation, purchase, sale, transmission and electricity directly to retail customers. The distribution of electric power in west and implementation of REPs as suppliers to retail central Texas. TNC also sells electric power customers has caused a significant shift in at wholesale to other utilities, municipalities, TNC s sales as described below under rural electric cooperatives and beginning in "Results of Operations. 2002 to its affiliated retail electric provider (REP) in Texas. In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed Wholesale power marketing activities are the obligations of the affiliated REP under the conducted on TNC s behalf byAEPSC. TNC, Texas Restructuring Legislation (see Note along with the other AEP electric operating 12). Prior to the sale, during 2002, sales to subsidiaries, shares in AEP s electric power the affiliated REP were classified as Sales to transactions with other utility systems and AEP Affiliates. Subsequent to the sale, power marketers. transactions with the REP will be classified as Wholesale Electricity or Energy Delivery. On January 1, 2002, customer choice of electricity supplier began in the Electric Results of Operations Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and In 2002, Net Income decreased $26.0 million Southwest Power Pool (SPP) regions of or 211 % primarily due to a $38.1 million long-Texas, with the majority of its operations lived asset impairment charge ($24.8 million being in the ERCOT territory. net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a Under the Texas Restructuring Legislation, $4.7 million impairment charge ($3.1 million each electric utility was required to submit a net of tax) related to the abandonment of a plan to structurally unbundle its business into wind-powered generation facility (see Note an affiliated REP, a power generator, and a 13). transmission and distribution utility. During the year 2000, TNC submitted a plan for Changes in Operatina Revenues separation that was subsequently approved Increase (Decrease) From Previous Year by the PUCT. TNC has functionally separated (in millions) h its generation from its transmission and distribution operations and AEP formed a wholesale Electricity* S(231. 7) (63) separate affiliated REP. Pending regulatory Energy Delivery* (95.7) (57) approval, TNC anticipates legally separating sales to AEP Affiliates 221.7 N.M. its generation from its transmission and Total (19) (*)05.7) distribution operations (see Note 8). The *Reflects the allocation of certain affiliated REP, a separate legal entitythatwas transmission and distribution revenues an AEP subsidiary (not owned by or included in bundled retail rates to energy delivery. consolidated with TNC) was sold in December 2002 (see Note 12). N.M. = Not Meaningful Since the affiliated REP is the electricity Wholesale Electricity revenues decreased as supplier to retail customers in the ERCOT a result of the elimination of TNCs retail area, TNC sells its generation to the affiliated electricity sales in the ERCOT region as of REP and other market participants and January 1,2002 and a decrease in wholesale provides transmission and distribution power marketing margins, partially offset by services to retail customers of the REPs inthe the ICR adjustments (see Note 6). D-2
Sales to AEP Affiliates increased primarily electricity at a significantly lower price than its due to increased revenues from the newly current cost to generate electricity, TNC created affiliated REP. Although TNC sold proposed in September 2002 to Inactivate electricity to the affiliated REP instead of various, high-cost gas fired generating directly to retail customers in the ERCOT facilities. TNC recorded an impairment region, total revenues decreased due to lower charge in the third quarter 2002 of prices for power sold to the affiliated REP. approximately $34.2 million related to these plants, which was recorded in Asset Additionally, delivery charges provided to the Impairments expense. In the fourth quarter affiliated REP in 2002 are classified as Sales 2002, an additional asset impairments charge to AEP Affiliates in 2002, whereas in 2001 of $3.9 million was also recorded in they were classified as Energy Delivery connection with these plants, along with a revenue. $4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, Changes in Operating Expenses a $1.2 million charge associated with fuel Increase (Decrease) From Previous Year inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (in millions) % (recorded in Other Operations) was recorded Fuel S(76.7) (43) in the fourth quarter of 2002 related to the Purchased Power: wholesale "inactivated plants. Electricity 10.0 14 AEP Affiliates (19 . 1) (34) other operation (6.3) (6) Depreciation and Amortization expense Asset Impairments 42.9 N.M. decreased due to the elimination in 2002 of Maintenance Depreciation and excess earnings expense under Texas Amortization (7.1) (14) Taxes other Restructuring Legislation and the elimination Than Income Taxes (5.8) (21) of regulatory asset amortization that ended in Income Taxes (18.1) N.M. Total gun 2) (15) 2001. N.M. = Not Meaningful The decrease in Taxes Other Than Income Fuel expense decreased due to adecrease in Taxes is primarily a result of one time 2001 the average unit cost of fuel and decreased assessments and a decrease in the gross generation required due to decreased energy receipts tax due to deregulation. sales. TNC used natural gas as fuel for 42% of its generation in 2002. The nature of the The decrease in Income Taxes is primarily a natural gas market is such that both long-term result of a decrease in pre-tax income and short-term contracts are generally based resulting from the impairment of various on the current spot market price. Changes in generating facilities. natural gas prices affect TNC s fuel expense; however, they generally did not impact results Other Changes of operations in 2001 due to fuel recovery mechanisms, which are no longer in place Nonoperating Income and Nonoperating beginning with deregulation in 2002. Expenses increased significantly as a result of increased non-utility revenue and expenses The net decline in total Purchased Power associated with energy related construction expense in 2002 was mainly due to both projects for third parties, offset in part by reduced MWHs purchased and reduced decreased interest income. The revenues prices, partially offset by ICR adjustments associated with the aforementioned energy (see Note 6). related construction projects included in Nonoperating Income increased $45.5 million Other Operation expense decreased slightly in 2002. The expenses associated with these in 2002 due to lower factoring and projects included in Nonoperating Expenses transmission expenses, offset in part by a increased $43.0 million in 2002.
$1.4 million write-down of material and supply inventory associated with the impaired plants. Interest Charges declined primarily due to As a result of TNC s recent ability to purchase lower interest rates.
D-3
it, AEP TEXAS NORTH COMPANY Statements of Operations Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $136,962 $368,741 $376,206 Energy Delivery 73,353 169,036 176,204 Sales to AEP Affiliates 240,425 18.681 18,654 TOTAL OPERATING REVENUES 450.740 556.458 571,064 OPERATING EXPENSES: Fuel 100,466 177,140 183,154 Purchased Power: wholesale Electricity 80,391 70,395 68,080 AEP Affiliates 37,582 56,656 57,773 Other operation 104,960 111,248 93,078 Asset Impairments 42,898 Maintenance 22,295 22,343 21,241 Depreciation and Amortization 43,620 50,705 55,172 Taxes other Than Income Taxes 22,471 28,319 25,321 Income Tax Expense (Credit) (11.814) 16.262 14,904 TOTAL OPERATING EXPENSES 442.869 523.068 518.723 OPERATING INCOME 7,871 33,390 52,341 NONOPERATING INCOME 53,763 12,199 9,530 NONOPERATING EXPENSES 54,755 10,695 12,664 NONOPERATING INCOME TAX CREDIT (289) (691) (1,459) INTEREST CHARGES 20.845 23.275 23.216 NET INCOME (LOSS) (13,677) 12,310 27,450 PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK > t12 20l6 $ 27,3A6 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME (LOSS) $(13,677) $12,310 $27,450 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (15) Minimum Pension Liability -(30.74) COMPREHENSIVE INCOME (LOSS) 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 Jed December 31. 2002 2001 2000 (in thousands) BEGINNING OF PERIOD $105,970 i;122,588 $113,242 NET INCOME (LOSS) (13,677) 12,310 27,450 DEDUCTIONS: cash Dividends Declared: Common Stock 20,247 28,824 18,000 Preferred stock 104 104 104 BALANCE AT END OF PERIOD 7192A2 $1I0,7=0 The common stock of TNC is owned by a who77y owned subsidiary of AEP. see notes to Financial Statements beginning on page L-1. D-5
AEP TEXAS NORTH COMPANY Balance Sheets December 31, 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 353,087 $ 443,508 Transmission 254,483 250,023 Distribution 445,486 431,969 General 111,679 112,797 Construction Work in Progress 37.012 22.575 Total Electric Utility Plant 1,201,747 1,260,872 Accumulated Depreciation and Amortization 521.792 546.162 NET ELECTRIC UTILITY PLANT 679 955 714,710 OTHER PROPERTY AND INVESTMENTS 1,213 24.933 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2.248
- 8.327 CURRENT ASSETS:
Cash and Cash Equivalents 1,219 2,454 Accounts Receivable: Customers 62,660 18,720 Affiliated Companies 43,632 8,656 Allowance for Uncollectible Accounts (5,041) (196) Fuel Inventory 12,677 8,307 Materials and Supplies 9,574 11,190 Accrued utility Revenues 6,829 Energy Trading and Derivative Contracts 4,130 10,240 Prepayments and other 1,070 966 TOTAL CURRENT ASSETS 136.750 60,337 REGULATORY ASSETS 45,097 54,122 DEFERRED CHARGES 11 912 2.446 TOTAL ASSETS $877.175 _$_8_64,875 See Notes to Financia7 Statements beginning on page L-1. 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 $137,214 $137, 214 Paid-in Capital 2,351 2,351 Accumulated other Comprehensive Income (Loss) (30,763) Retained Earnings 71.942 105.970 Total Common shareholder s Equity 180,744 245,535 Cumulative Preferred Stock Not subject to Mandatory Redemption 2,367 2,367 Long-term Debt 132. 500 220,967 TOTAL CAPITALIZATION 468.869 OTHER NONCURRENT LIABILITIES 28, 861 6,296 CURRENT LIABILITIES: short-term Debt Affiliates 125,000 Long-term Debt Due within One Year 35,000 Advances from Affiliates 80,407 50,448 Accounts Payable General 32,714 33,782 Accounts Payable Affiliated Companies 76,217 11,388 customer Deposits 117 4,191 Taxes Accrued 3,697 17,358 Interest Accrued 2,776 4,762 Energy Trading and Derivative Contracts 3,801 12,402 other 17.414 9. 824 TOTAL CURRENT LIABILITIES 342,143 179 155 DEFERRED INCOME TAXES 117, 521 145.049 DEFERRED INVESTMENT TAX CREDITS 21.510 22,781 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 557 52250 REGULATORY LIABILITIES AND DEFERRED CREDITS 50,972 37.475 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $87,17 see Notes to Financia7 statements beginning on page L-1. D-7
AEP TEXAS NORTH COMPANY Statements of Cash Flows Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $(13,677) $ 12,310 $ 27,450 Adjustments to Reconcile Net Income to Net Cash Flows From operating Activities: Depreciation and Amortization 43,620 50,705 55,172 writedown of Utility Assets 38,154 writedown of wind Farm Assets 4,744 Deferred Income Taxes (12,275) (11,891) 8,164 Deferred Investment Tax credits (1,271) (1,271) (1,271) Mark-to-Market Energy Trading and Derivative Contracts (1,127) (3,506) 2,590 CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: Accounts Receivable (net) (74,071) 24,844 (1,445) Fuel, Materials and supplies (2,754) 3,187 8,478 Accrued Utility Revenues (6,829) Accounts Payable 63,761 (42,604) 28,393 Taxes Accrued (13,661) (1,543) 6,443 Fuel Recovery 14,169 32,505 (53,841) Transmission Coordination Agreement settlement 15,465 change in other Assets (16,928) (1,432) 2,549 Change in other Liabilities 16, 514 11,056 (3.869) Net cash Flows From Operating Activities 38. 369 72. 360 94,278 INVESTING ACTIVITIES: Construction Expenditures (43,563) (39,662) (64,477) sales Proceeds and other 150 (127) Net Cash used For Investing Activities (43,413) (39.789) (64,477) FINANCING ACTIVITIES: Retirement of Long-term Debt (130,799) (48,000) change in short-term Debt Affiliated (net) 125,000 Change in Advances from Affiliates (net) 29,959 (8,130) 37,170 Dividends Paid on Common stock (20,247) (28,824) (18,000) Dividends Paid on cumulative Preferred Stock (104) (104) (104) Net Cash Flows From (used For) Financing Activities 3 809 (37,058) (28.934) Net Increase (Decrease) in cash and cash Equivalents (1,235) (4,487) 867 cash and cash Equivalents at Beginning of Period 2,454 6.941 6.074 Cash and cash Equivalents at End of Period $-1,2-19 i__2,54 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) COMMON SHAREHOLDER S EQUITY $180.744 S245.535 PREFERRED STOCK: $100 par value authorized shares 810,000 Call Price shares December 31, Number of Shares Redeemed outstanding Series 2002 Year Ended December 31. December 31. 2002 2002 2001 2000 Not subject to Mandatory Redemption: 4.40% $107 - - 1 23,672 2,367 2,367 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 88,190 211,657 Installment Purchase Contracts 44,310 44,310 Less Portion Due within one Year (35 000) Long-term Debt Excluding Portion Due within one Year 132. 500 220.967 TOTAL CAPITALIZATION See Notes to Financia7 Statements beginning on page L-1. D-9
AEP TEXAS NORTH COMPANY Schedule of LonQ-term Debt First mortgage bonds outstanding were as Under the terms of the installment purchase follows: contracts, TNC is required to pay amounts December 31. sufficient to enable the payment of interest on 2002 2001 (in thousaniis-Y and the principal of (at stated maturities and % Rate Due 6-7/8 2002 October 1 S - S 35,000 upon mandatory redemptions) related 7 2004 October 1 18,469 40,000 pollution control revenue bonds issued to 6-1/8 2004 February 1 24,036 40,000 6-3/8 2005 October 1 37,609 72,000 finance the construction of pollution control 7-3/4 2007 June 1 unamortized Discount 8,151 (75) 25,000 (343) facilities at certain plants. Q8 i2IL-6S At December 31, 2002, future annual long-First mortgage bonds are secured by a first term debt payments are as follows: mortgage lien on electric utility plant. The Amount indenture, as supplemented, relating to the (in thousands) first mortgage bonds contains maintenance 2003 $ - and replacement provisions requiring the 2004 42,505 2005 37,609 deposit of cash or bonds with the trustee, or in 2006 - 2007 8,151 lieu thereof, certification of unfunded property Later Years 44 310 additions. Principal Amount Less: unamortized Discount 132,575 C75) Total S 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 Red River Authority of Texas: 6.00 2020 June 1 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. Inour 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 1 IJ .IIU
...f J. 1*
I - . 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,814,470 $1,784,259 $1,759,253 $1,586,050 $1,672,244 Operating Expenses 1,512,407 1.509.273 1.558.099 1,344,814 1.443.701 Operating Income 302,063 274,986 201,154 241,236 228, 543 Nonoperating Items, Net 20,106 6,868 11,752 8,096 (8,301) Interest Charges 116.677 120,036 148.000 128.840 126.912 Income Before Extraordinary Item 205,492 161,818 64,906 120,492 93,330 Extraordinary Gain 8.938 Net Income 205,492 161,818 73,844 120,492 93,330 Preferred stock Dividend Requirements 2.897 2.011 2,504 2.706 2.497 Earnings Applicable to common Stock $ 202,195 $ 159&0QZ December 31, 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,895,303 $5,664,657 $5,418,278 $5,262,951 $5,087,359 Accumulated Depreciation and Amortization 2.424.607 2. 296. 481 2. 188. 796 2.079.490 1.,984. 856 Net Electric Utility Plant 3229,482 SI-1MA61 Total Assets _4 &62.7 847 $6.522 l 9S 14.35Z2 V4,047,038 Common Stock and Paid-in Capital $ 977,700 $ 976,244 $ 975,676 $ 974,717 $ 924,091 Accumulated other comprehensive Income (Loss) (72,082) (340) Retained Earnings 260,439 150, 797 120, 584 175. 854 179.461 Total Common Shareholder's Equity ,166 Q5Z I 1,12-6 7 0- $1.,096,260Q $103A52 cumulative Preferred Stock: Not subject to Mandatory Redemption $ 17,790 $ 17,790 $ 17,790 $ 18,491 $ 19,359 Subject to Mandatory Redemption 10.860 10,860 10,860 20,310 22.310 Total Cumulative Preferred Stock $ 28.650 $1__3 Oi Long-term Debt (a) IL,55-6-55-9 $1,605,818 t1<6 65, _$It55L455 obligations under Capital Leases (a) L-3i,5&89 $ 46,281 $ 64,645 Si__5d751z Total Capitalization And Liabilities t{A,621T4~ $4Z482,78 $6557255 $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 2001 primarily due to the effect of a court generation, purchase, sale, transmission and decision related to a corporate owned life distribution of electric power to 925,000 retail insurance (COLI) program recorded in 2000. customers in southwestern Virginia and In February 2001, the U.S. District Court for southern West Virginia. APCo, as a member the Southern District of Ohio ruled against of the AEP Power Pool, shares in the AEP and certain of its subsidiaries, including revenues and costs of the AEP Power Pool's APCo, in a suit over deductibility of interest wholesale sales to neighboring utility systems claimed in AEP s consolidated tax return and power marketers including power trading related to COLI. In 1998 and 1999 APCo paid transactions. APCo also sells wholesale the disputed taxes and interest attributable to power to municipalities. the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in The cost of the AEP Power Pool's generating net income was growth in and strong capacity is allocated among the Pool performance by the wholesale electricity members based on their relative peak business in the first half of 2001 offset in part demands and generating reserves through by the effect of extremely mild weather in the payment of capacity charges and the November and December combined with receipt of capacity credits. AEP Power Pool weak economic conditions which reduced members are also compensated for their out- retail energy sales. of-pocket costs of energy delivered to the AEP Power Pool and charged for energy Operating Revenues received from the AEP Power Pool. The AEP Power Pool calculates each company's prior Operating Revenues increased $30 million or twelve month peak demand relative to the 2% in 2002 as a result of weather related total peak demand of all member companies demand and increased generation resulting as a basis for sharing revenues and costs. from availablility of plants previously down for The result of this calculation is the member maintenance coming back online. An increase load ratio (MLR) which determines each of $25 million, or 1%, in 2001 Operating company's percentage share of revenues and Revenues was attributable to an increase in costs. AEP Power Pool transactions. Changes in components of revenues were as follows: Results of Operations Increase (Decrease) From Previous Year (dollars in millions) Net Income increased $44 million or 27% in 2002 2001 2002 due to higher retail sales resulting from Amount % Amount % wholesale increased generation, weather related El ectri ci ty* $16.0 2 S(11.7) (1) electricity demands and reductions in Energy Delivery* (1.0) Sales to AEP
- 20.1 3 Maintenance expense. Most significantly, the Affiliates 15.2 9 16.6 11 Total Mountainer, Amos and Glen Lyn plants, down Revenues 5302 2 L25 0 1 for boiler maintenance in 2001, were back
*Reflects the allocation of certain online in 2002 resulting in increased transmission and distribution revenues availability of generation and decreased included in bundled retail rates to energy delivery.
maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased $10 million as a result of Operating Revenues for 2002 increased as a a reduction in trading incentive compensation result of an increase in generation and recorded in Nonoperating Expenses offset in availability at the Mountaineer, Amos and part by decreased power trading gains Glen Lyn plants; and increases in residential recorded in Nonoperating Income. and commercial sales due to warmer weather during July and September. Sales to AEP Net Income increased $88 million or 119% in affiliates increased for the year due to an E-2
increase in generation capacity and power of an increase in APCo generation. available to be delivered to AEP Power Pool. Mountaineer, Amos, and Glen Lyn plants had These increases were partially offset by flat undergone boiler plant maintenance in 2001 industrial sales as recessionary conditions which resulted in increased availability in continued into 2002. 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of The year 2001 saw a decrease in kilowatt scheduled plant maintenance. hour sales to industrial customers. This decrease was due to the economic recession. Wholesale Electricity Purchases increased for In the fourth quarter, sales to residential and 2002 as a result of increased purchases from commercial customers declined, reflecting third parties for resale to wholesale customers recession-related reductions in demand. and to meet internal demand. Electricity purchased power expense increased in 2001 The increase in Sales to AEP Affiliates in due to increases inwholesale electricity prices 2001 isdue to an increase in AEP Power Pool and as a result of the previously mentioned transactions. As the quantity of energy sold plant outages. by the AEP Power Pool rose, APCo s contribution of energy to the Pool rose, The decrease for 2002 in Purchases from accounting for the increase in APCo s AEP Affiliates is a result of increased internal revenues from Sales to AEP Affiliates. generation due to plant availability. Purchased power from AEP affiliates decreased in 2001 Operating Expenses as the result of a decrease in AEP Power Pool capacity charges due to a reduction in Operating Expenses for 2002 were APCo s MLR. comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Other Operation expense increased in 2002 Power expenses were offset by decreases in mainly due to severance expenses related to power purchases from AEP Affiliates due to the sustained earnings initiative plan, a increases in APCo generation and availability reduction in the gains recorded on the as plants previously down for maintenance dispositions of S02 emission allowances, and resumed operations. The decrease in increased insurance premiums and other operating expenses in 2001 of 3% is due to employee benefit costs. These increases decreases in income taxes, other operation were offset by reduced trading overhead expense, fuel expense and taxes other than expenses as a result of reduced staffing and income taxes partially offset by increases in weaker market conditions; a decrease in electricity purchased power expense and transmission equalization charges caused by depreciation and amortization expenses. a reduction in APCo s MLR ratio; and energy Changes in the components of Operating delivery severance accruals recorded in 2001 Expenses are as follows: for which there was no comparable activity in Increase (Decrease) 2002. Other operation expense decreased in From Previous Year 2001 mainly due to the effect of AEPSC (dolTlars in millions) 2002 2001 billings in 2000 for the disallowance of the Amount % Amount % COLI program interest deduction. Additionally, Fuel S 79.4 23 S (17.6) (5) the decrease was the result of a gain wholesale Electricity recorded on the disposition of S02 emission Purchases 15.0 36 17.4 70 allowances offset in part by increased AEP Affiliate Purchases (112.3) (32) (8.9) (3) wholesale power trading incentive other operation 8.9 3 (18.6) (7) compensation expense. Maintenance (10.2) (8) 7.9 - 6 Depreciation and Amortization 8.9 5 17.3 11 The decrease in Maintenance expense in Taxes other Than Income Taxes (4.6) (5) (11.8) (11) 2002 is primarily due to previously discussed Income Taxes 18.0 19 (34. 5) (27) boiler plant maintenance at Amos, Total __3.1 - (3) Mountaineer and Glen Lyn plants in the year Fuel expense increased for 2002 as a result 2001. E-3
Depreciation and Amortization expense trading gains driven by a decline in market increased during 2002 due to increased prices. Nonoperating Expenses decreased as amortization for the net generation-related a result of decreased trading incentives. The regulatory assets related to the Companys increase in Nonoperating Income and West Virginia jurisdiction which were assigned Nonoperating Expenses for 2001 is due to to the distribution portion of the Companys considerable increases in the level of activity business and are being recovered through in the wholesale business s trading regulated rates. Investment in production transactions outside of the AEP System s plant in service, primarily equipment related to traditional marketing area. emission control, contributed to the increase in depreciation and amortization expense. Interest Charges Depreciation and Amortization expense Interest Charges for 2002 decreased primarily increased in 2001 due to accelerated as a result of lower AEP money pool balances amortization, beginning in July 2000, of the and interest rates and the retirement of first transition regulatory assets in the Virginia and mortgage bonds in 2001. Interest charges West Virginia jurisdictions. Additional decreased in 2001 primarily due to the effect investments in distribution and transmission of recognizing in 2000 previously deferred plant also contributed to the increases in interest payments to the IRS related to the depreciation and amortization expense in COLI disallowances and interest on resultant 2001. During June 2000 we discontinued the state income tax deficiencies. Additionally, application of SFAS 71 in the Virginia and the decrease in 2001 is due to the retirement West Virginia jurisdictions. Consequently net of first mortgage bonds in 2000. 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. 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 Year Ended December 3L. 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $1,')33,904 $1,017,938 $1,029,657 Energy Delivery 594,089 595,036 574,918 Sales to AEP Affiliates 186.477 171,285 154.678 Total Operating Revenues 1.314.470 1.784.259 1.759.253 OPERATING EXPENSES: Fuel 430,963 351,557 369,161 Purchased Power: wholesale Electricity 57,091 42,092 24,720 AEP Affiliates 234,597 346,878 355,774 Other operation 269,426 260,518 279,114 Maintenance 122,209 132,373 124,493 Depreciation and Amortization 189,335 180,393 163,089 Taxes other Than Income Taxes 95,249 99,878 111,692 Income Taxes 113.537 95. 584 130.056 Total operating Expenses 1,512.407 1,509.273 1.558.099 OPERATING INCOME 302,063 274,986 201,154 NONOPERATING INCOME 29,278 49,507 31,204 NONOPERATING EXPENSES 11,783 41,500 16,329 NONOPERATING INCOME TAX EXPENSE (BENEFIT) (2,611) 1,139 3,123 INTEREST CHARGES 116.677 120.036 148.000 INCOME BEFORE EXTRAORDINARY ITEM 205,492 161,818 64,906 EXTRAORDINARY GAIN DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) 8.938 NET INCOME 205,492 161,818 73,844 PREFERRED STOCK DIVIDEND REQUIREMENTS 2.897 2.011 2.504 EARNINGS APPLICABLE TO COMMON STOCK -$ZLn-A0 Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME $205,492 $161,818 $73,844 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (1,580) (340) Minimum Pension Liability (70,162) COMPREHENSIVE INCOME $13,50 S161,AIA see Notes to Financia7 Statements beginning on page L-1. E-5
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31. 2002 2001 2000 (in thousands) Retained Earnings January 1 $150,797 $120,584 $175,854 Net Income 205.492 161,818 73,844 356.289 282.402 249,698 Deductions: cash Dividends Declared: Common stock 92,952 129, 594 126,612 Cumulative Preferred Stock: 4-1/2% series 801 801 811 5.90% Series 278 278 307 5.92% Series 364 364 364 6.85% series 289 Total cash Dividends Declared 94,395 131,037 128,383 capital Stock Expense 1.455 568 731 Total Deductions 95.850 131.605 129.114 Retained Earnings December 31 $260,4139- $150,797 See Notes to Financia7 Statements beginning on page L-1. E-6
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31. 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,245,945 $2,093,532 Transmi ssion 1,218,108 1,222,226 Distribution 1,951,804 1,887,020 General 272,901 257,957 Construction work in Progress 206.54 5 203,922 Total Electric utility Plant 5 ,895,303 5, 664 ,657 Accumulated Depreciation and Amortization 2,424.607 2. 296. 48. NET ELECTRIC UTILITY PLANT 3,470.696 3. 368. 176 OTHER PROPERTY AND INVESTMENTS 54.653 53. 736 LONG-TERM ENERGY TRADING CONTRACTS 115,748 119,638 CURRENT ASSETS: cash and cash Equivalents 4,285 13,663 Accounts Receivable: Customers 132,266 113,371 Affiliated Companies 122,665 63,368 Mi scellaneous 28, 629 11,847 Allowance for uncollectible Accounts (13,439) (1,877) Fuel Inventory 53,646 56,699 Materials and supplies 59,886 59,849 Accrued utility Revenues 30,948 30,907 Energy Trading and Derivative Contracts 94,238 137,742 Prepayments and other 13.396 16.018 TOTAL CURRENT ASSETS 526.,520 501.587 REGULATORY ASSETS 395.,553 397. 383 DEFERRED CHARGES 64. 677 42, 265 TOTAL ASSETS see Notes to Financial Statements beginning on page L-1. 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 $ 260,458 $ 260,458 Paid-in Capital 717,242 715,786 Accumulated other comprehensive Income (Loss) (72,082) (340) Retained Earnings 260.439 150.797 Total Common Shareowner s Equity 1,166,057 1,126,701 Cumulative Preferred stock: Not subject to Mandatory Redemption 17,790 17,790 subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,738,854 1.476. 552 TOTAL CAPITALIZATION 2,933,561 2.631.903 OTHER NONCURRENT LIABILITIES 173.438 84,104 CURRENT LIABILITIES: Long-term Debt Due within One Year 155,007 80,007 Advances From Affiliates 39,205 291,817 Accounts Payable General 141,546 127,597 Accounts Payable Affiliated Companies 98,374 84,518 Taxes Accrued 29,181 55,583 Customer Deposits 26,186 13,177 Interest Accrued 22,437 21,770 Energy Trading and Derivative Contracts 69,001 121,161 other 79. 832 79.089 Total CURRENT LIABILITIES 660.769 874.719 DEFERRED INCOME TAXES 701.801 703. 575 DEFERRED INVESTMENT TAX CREDITS 33.691 38,328 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 44.517 60. 518 REGULATORY LIABILITIES AND DEFERRED CREDITS 80,070 89, 638 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $4,62L,847 A4-82, 25 See Notes to Financial statements beginning on page L-1. E-8
APPALACHIAN POWER COMPANY AND SUBSIDIARIES consolidated Statements of Cash Flows Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $ 205,492 $ 161,818 $ 73,844 Adjustments for Noncash Items: Depreciation and Amortization 189,335 180, 505 163,202 Deferred Income Taxes 16,777 42,498 8,602 Deferred Investment Tax credits (4,637) (4,765) (4,915) Deferred Power Supply Costs (net) 6,365 1,411 (84,408) Mark-to-Market of Energy Trading Contracts (21, 151) (68,254) (1,843) Provision for Rate Refunds (4,818) Extraordinary Gain (8,938) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (83,412) 134,099 (166,911) Fuel, Materials and supplies 3,016 (19,957) 18,487 Accrued Utility Revenues (41) 35,592 (13,081) Accounts Payable 27,805 (45,073) 159,369 Taxes Accrued (26,402) (7,675) 14,220 Revenue Refunds Accrued 181 Incentive Plan Accrued (858) (2,451) 10,662 Disputed Tax and Interest Related to COLI 72,440 change in operating Reserves (3,190) (5,358) (19,770) Rate Stabilization Deferral 75,601 change in other Assets (43,337) 19,418 (13,021) change in other Liabilities 14,948 (27.954) 9.817 Net Cash Flows From Operating Activities 280,710 393. 854 288. 720 INVESTING ACTIVITIES: Construction Expenditures (276, 549) (306,046) (199,285) Proceeds From sales of Property and other 1,074 1,182 159 Net Cost of Removal and Other (8.434) (7.500) Net Cash Flows used For Investing Activities (275.475) (313.298) (206. 626) FINANCING ACTIVITIES: Issuance of Long-term Debt 647,401 124,588 74,788 Retirement of cumulative Preferred stock (9,924) Retirement of Long-term Debt (315,007) (175,000) (136,166) change in short-term Debt (net) (191,495) 68,015 Change in Advances From Affiliates (252,612) 300,204 (8,387) Dividends Paid on Common stock (92,952) (129,594) (126,612) Dividends Paid on cumulative Preferred Stock (1.443) (1.443) (1.938) Net cash Flows used For Financing Activities (14,613) (72.740) (140,224) Net Increase (Decrease) in cash and Cash Equivalents (9,378) 7,816 (58,130) cash and cash Equivalents January 1 13.663 5 $847 63.977 cash and cash Equivalents December 31 $ 4,285 $ 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) COMMON SHAREHOLDER S EQUITY S1.166.057 $1.126.701 PREFERRED STOCK: No par value - authorized shares 8,000,000 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 (b): 4-1/2% $110 6 - 7,011 177,899 17.790 17.790 subject to Mandatory Redemption (b): 5.90% cc) - - 10,000 47,100 4,710 4,710 5.92% Cc) _ _ - 61, 500 6.150 6.150 10.860 10.860 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 489,697 639,365 Installment Purchase Contracts 235,027 234,904 senior unsecured Notes 1,166,609 518,247 Junior Debentures 161, 507 other Long-term Debt 2,528 2,536 Less Portion Due within one Year (155.007) (80.007) Long-term Debt Excluding Portion Due within one Year 1.738.854 1.476.552 TOTAL CAPITALIZATION 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 Under the terms of the installment purchase follows: contracts, APCo is required to pay amounts December 31. sufficient to enable the payment of interest on 2002 2001 (in thousands) and the principal of (at stated maturities and % Rate Due 7.38 2002 August 15 'S - $ 50,000 upon mandatory redemptions) related 7.40 2002 - December 1 30,000 pollution control revenue bonds issued to 6.65 2003 - May 1 40,000 6.85 2003 - June 1 30,000 finance the construction of pollution control 6.00 2003 - November 1 30,000 30,000 facilities at certain plants. 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 Senior unsecured notes outstanding were as 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 100,000 follows: 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 30,237 30, 237 December 31. 7.15 2023 - November 1 20,000 20,000 2002 2001 7.125 2024 - May 1 45,000 45,000 (in thousands) 8.00 2025 - June 1 45,000 45,000 X Rate Due unamortized Discount -1C 540) (1.872) (a) 2003 August 20 S 125,000 5125,00 0 Total M69,36 7.45 2004 - November 1 50,000 50,000 4.80 2005 June 15 450,000 - First mortgage bonds are secured by a first 4.32 2007 November 12 200,000 - 6.60 2009 - May 1 150,000 150,00 0 mortgage lien on electric utility plant. Certain 7.20 2038 - March 31 100,000 100,00 0 supplemental indentures to the first mortgage 7.30 2038 - June 30 100,000 100,00 0 unamortized Discount 8 391 6.75 lien contain maintenance and replacement Total VIA609 S51,2 z provisions requiring the deposit of cash or (a) A floating interest rate is determined bonds with the trustee, or in lieu thereof, monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, certification of unfunded property additions. respectively. Installment purchase contracts have been Junior debentures outstanding were as entered into, in connection with the issuance follows: of pollution control revenue bonds, by December 31. governmental authorities as follows: 2002 (in thousands) 2001 8-1/4% Series A due December 31. 2002 2001 2026 September 30 S - S 75,000 8% Series B due 2027 (in thousands) % Rate Due - March 31 90,000 Industrial Development unamortized Discount (3 . 493) Total U161, 50 Authority of Russell county, Virginia: At December 31, 2002, future annual long-7.70 2007 - November 1 S 17, 500 S 17, 500 5.00 2021 - November 1 19,500 19, 500 term debt payments are as follows: Putnam County, West Virginia: Amount (in thousands) 5.45 2019 - June 1 410,000 40,000 2003 S 155,007 6.60 2019 - July 1 30,000 30,000 2004 121,008 2005 530,010 Mason County, West Virginia: 2006 100,011 2007 217,513 7-7/8 2013 - November 1 10,000 10,000 Later Years 782. 216 6.85 2022 - June 1 40,000 40,000 Total Principal Amount 1,905,765 6.60 2022 - October 1 50,000 50,000 unamortized Discount (11,904) 6.05 2024 - December 1 30,000 30,000 Total unamortized Discount 1. 973) (2 096) Total 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. combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 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 Asset Impairments and Investments Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 supplementary Information Note 20 Leases Note 22 Lines of credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 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 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $1,400,160 $1,350,319 $1,304,409 $1,190,997 $1,187,745 operating Expenses 1180T3 81 1.098.142 1.108.532 968.207 975, 534 operating Income 219,779 252,177 195,877 222,790 212,211 Nonoperating Items, Net 15,263 7,738 5,153 2,709 (1,343) Interest charges 53. 869 68.015 80,828 75. 229 77.824 Income Before Extraordinary Item 181,173 191,900 120,202 150,270 133,044 Extraordinary Loss (30.024) (25. 236) Net Income 181,173 161,876 94,966 150,270 133,044 Preferred Stock Dividend Requirements 1.095 2.131 2.131 Earnings Applicable to common Stock £__1798JA1 $ 160.781 $18 139 £ 410Q9f Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric utility Plant $3,467,626 $3,354,320 $3,266,794 $3,151,619 $3,053,565 Accumulated Depreciation 1.465.174 1.377.032 1.299.697 1.210.994 1.134. 348 Net Electric utility Plant £2_Q02 ,452 $1,977,288 £1,40,625 $1,912,=21 Total Assets $Z,153,240 3$Z.2 "388 _$13 X&ZL42i $ &08Q8123 Common stock and Paid-in capital $ 616,410 $ 615,395 $ 614,380 $ 613,899 $ 613,518 Accumulated other comprehensive Income (LoSS) (59,357) Retained Earnings 290.611 176.103 99.069 246, 584 186.441 Total Common shareholder's Equity $_847 7 604 =$191 9,AH $ 713,449 $860.,483 $Z 79R9,9 cumulative Preferred stock - subject to Mandatory Redemption (a) $ 252i0f $L 25,000 Long-term Debt (a) $ _ 9 2 4. 54 5 L Z& L$ L6 1 Q6Z Obligations under Capital Leases (a) $L 72293& S 4_0ZZ0 L A42L3Z Total Capitalization R2$i_ 4 Q and Liabilities $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 Changes in the components of Operating public utility engaged in the generation, Revenues were: purchase, sale, transmission and distribution Increase (Decrease) of electric power to 689,000 retail customers From Previous Year (dollars in millions) in central and southern Ohio. CSPCo as a Amount % member of the AEP Power Pool shares in the Retail* S51 8 wholesale Marketing 3 2 revenues and costs of the AEP Power Pool's unrealized MTM (4) (22) wholesale sales to neighboring utility systems Other wholesale Electricity* 1 51 3 6 and power marketers including power trading Energy Delivery* 9 2 transactions. CSPCo also sells wholesale Sales to AEP Affiliates (10) (15) Total Revenues $5Q 4 power to municipalities.
- Reflects the allocation of certain transmission and distribution revenues The cost of the AEP Power Pool's generating included in bundled retail rates to energy delivery.
capacity is allocated among the Pool members based on their relative peak During the summer months, cooling degree demands and generating reserves through days increased 35%. For the fall season, the payment of capacity charges and receipt heating degree days increased 34%. This of capacity credits. AEP Power Pool reflects a return to more normal weather members are also compensated for their out- conditions since the weather experienced in of-pocket costs of energy delivered to the 2001 was abnormally mild. AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Operating Expenses Power Pool calculates each company's prior twelve month peak demand relative to the Operating Expenses increased in2002 mainly total peak demand of all member companies as a result of purchased power, operating as a basis for sharing AEP Power Pool expenses and state taxes. revenues and costs. The result of this calculation is the member load ratio (MLR) Changes in the components of Operating which determines each companies Expenses were: percentage share of AEP Power Pool revenues and costs. Increase (Decrease) From Previous Year (dollars in millions) Amount X Results of Operations Fuel $10 6 wholesale Purchased Net Income increased $19 million or 12% in Power 4 37 2002 due to reduced interest charges and a AEP Affiliates Purchased Power 18 6 $30 million extraordinary loss recorded in other operation Expenses 18 8 Maintenance Expense (2) (4) 2001 to recognize prepaid Ohio excise taxes Depreciation and stranded by Ohio deregulation offset by higher Amortization 4 3 Taxes other Than operating expenses. Income Taxes 25 22 Income Taxes 5 5 Total 7 Operating Revenues Fuel cost increased as a result of a 10% Operating Revenues increased in 2002 increase in generation partially offset by a mainly as a result of increased residential and slight cost decrease per ton of coal commercial sales due to demand caused by consumed. weather conditions. Wholesale Purchased Power increased in 2002 due to increased purchases from third F-2
parties for resale to wholesale customers and Nonoperating Income and Nonoperating to meet internal demand. Expense Expenses related to AEP Affiliates Purchased The decrease in Nonoperating Income in Power increased due to greater system pool 2002 is due to a reduction in net gains from capacity charges. AEP Power Pool trading transactions outside of the AEP System s traditional marketing The increase in Other Operation expenses area. The AEP Power Pool enters into power was attributable to a number of factors: trading transactions for the purchase and sale higher OPEB post retirement costs as aresult of electricity and for options, futures and of higher medical cost and lower investment swaps. CSPCo s share of the AEP Power performance, 2002 Sustained Earnings Pool s gains and losses from forward Initiative Expenses, and the 2001 reversal of electricity trading transactions outside of the a quality of service liability accrual. The AEP System traditional marketing area and increase was partially offset by a reduction in for speculative financial transactions (options, energy trading overheads reflecting reduced futures, swaps) is included in Nonoperating marketing activity. Income. The decrease reflects a reduction in electricity prices and margins due to a The increase in Taxes Other Than Income decrease in demand. Taxes in 2002 is due to an increase in property taxes and a full year of the state The decrease in Nonoperating Expenses in excise tax which replaced the state gross 2002 was due to a decrease in energy trading receipts tax during 2001. incentive compensation. The increase in Income Taxes is Nonoperating Income Tax Expense increased predominately due to an increase in state in 2002 due to increase in pre-tax taxes as a result of the State of Ohio s tax nonoperating income. legislation resulting from utility deregulation. This increase was offset in part by a decrease Interest Charges in federal taxes due to a decrease in pre-tax operating income. 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 Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity S 850,680 S 799,589 $ 856,998 Energy Delivery 492,278 483,219 398,046 sales to AEP Affiliates 57,202 67,511 49. 365 Total operating Revenues 1.400.160 1,350.319 1,304.409 OPERATING EXPENSES: Fuel 185,086 175,153 189,155 Purchased Power: Wholesale Electricity 15,023 10,957 9,879 AEP Affiliates 310,605 292,199 287,750 other operation 237,802 219,497 219,840 Maintenance 60,003 62,454 69,676 Depreciation and Amortization 131,624 127,364 99,640 Taxes other Than Income Taxes 136,024 111,481 123,223 Income Taxes 104.214 99.037 109, 369 TOTAL OPERATING EXPENSES 1,180.381 1 098.142 1.108, 532 OPERATING INCOME 219,779 252,177 195,877 NONOPERATING INCOME 26,360 32,756 20,580 NONOPERATING EXPENSES 4,308 21,095 8,070 NONOPERATING INCOME TAX EXPENSE 6,789 3,923 7,357 INTEREST CHARGES 53 869 68,015 80.828 INCOME BEFORE EXTRAORDINARY ITEM 181,173 191,900 120,202 EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (Note 2) (30.024) (25, 236) NET INCOME 181,173 161,876 94,966 PREFERRED STOCK DIVIDEND REQUIREMENTS 1.332 1.095 1.783 EARNINGS APPLICABLE TO COMMON STOCK $ 179, 841 $ ~93,13 Consolidated Statements of Comprehensive Income Year Ended December 31. 21'02 2001 2000 (in thousands) NET INCOME 18: 1,173 $161,876 $94,966 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (267) Minimum Pension Liability (M9. 090) COMPREHENSIVE INCOME $12 3261,B 6 594--9-U The common stock of the CSPCo is who7ly owned by AEP. See Notes to Financial Statements beginning on page L-1. 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 $176,103 $ 99,069 $246,584 Net Income 181,173 161.876 94.966 357,276 260.945 341.550 Deductions: cash Dividends Declared: Common Stock 65,300 82,952 240,600 Cumulative Preferred Stock 7% series 350 875 1.400 Total cash Dividends Declared 65,650 83,827 242,000 capital stock Expense 1.015 1.015 481 Total Deductions 66.665 84.842 242.481 Retained Earnings December 31 $290,611. $i176,13 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 $1,582,627 $1,574,506 Transmission 413,286 401,405 Distribution 1,208,255 1,159,105 General 165,025 146,732 Construction work in Progress 98.433 72.572 Total Electric Utility Plant 3,467,626 3,354,320 Accumulated Depreciation 1.465,174 1,377.032 NET ELECTRIC UTILITY PLANT 2,002X452 1,977.288 OTHER PROPERTY AND INVESTMENTS 35.759 40.369 LONG-TERM ENERGY TRADING CONTRACTS 77.810 73. 310 CURRENT ASSETS: cash and cash Equivalents 1,479 12,358 Advances to Affiliates 31,257 Accounts Receivable: Customers 49,566 41,770 Affiliated Companies 54,518 63,470 Miscellaneous 22,005 16,968 Allowance for uncollectible Accounts (634) (745) Fuel 24,844 20,019 Materials and supplies 40,339 38,984 Accrued Utility Revenues 12,671 7,087 Energy Trading Contracts 63,348 84,323 Prepayments and other Current Assets 7.308 28.733 TOTAL CURRENT ASSETS 306.701 312.967 REGULATORY ASSETS 257.682 262.267 DEFERRED CHARGES 72,836 56,187 TOTAL ASSETS $2,753,240 $2,722,388 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 $ 41,026 $ 41,026 Paid-in capital 575,384 574,369 Accumulated other comprehensive Income (Loss) (59,357) Retained Earnings 290.611 176,103 Total Common Shareholder s Equity 847,664 791,498 cumulative Preferred stock subject to Mandatory Redemption 10,000 Long-term Debt - General 418,626 571,348 Long term Debt Affiliated companies 160,000 TOTAL CAPITALIZATION 1,426.290 1.372.846 OTHER NONCURRENT LIABILITIES 95,460 36,715S CURRENT LIABILITIES: Long-term Debt Due within One Year General 43,000 20,500 Long-term Debt Due within One Year Affiliated Companies 200,000 short-term Debt Affiliated Companies 290,000 Advances from Affiliates 181, 384 Accounts Payable General 89,736 60,689 Accounts Payable Affiliated companies 81,599 83,697 Taxes Accrued 112,172 116,364 Interest Accrued 9,798 10,907 Energy Trading Contracts 46,375 72,082 other 36,790 36, 305 TOTAL CURRENT LIABILITIES 709.470 781,928 DEFERRED INCOME TAXES 437.771 443, 722 DEFERRED INVESTMENT TAX CREDITS 33.907 37.176 LONG-TERM ENERGY TRADING CONTRACTS 29.926 37.101 DEFERRED CREDITS 20.416 12.900 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $Za53 24Q £tZ722za83 See Notes to Financia7 Statements beginning on page L-1. F-7
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income S 181,173 $ 161,876 S 94,966 Adjustments for Noncash Items: Depreciation and Amortization 131,753 128,500 100,182 Deferred Income Taxes 23,292 24,108 (4,063) Deferred Investment Tax credits (3,269) (4,058) (3,482) Deferred Fuel Costs (net) 5,352 Mark to Market of Energy Trading Contracts (16,667) (44,680) (3,393) Extraordinary Loss 30,024 25,236 Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (3,992) 19,987 (29,737) Fuel, Materials and supplies (6,180) (7,780) 11,957 Accrued Utility Revenues (5,584) 2,551 38,479 Accounts Payable 26,949 (16,249) 81,284 Disputed Tax and Interest Related to COLI 39,483 Change in other Assets (8,027) (42,066) (121,115) change in other Liabilities (22,448) (18,769) 132.44 Net cash Flows From Operating Activities 297,000 233,444 367,590 INVESTING ACTIVITIES: Construction Expenditures (136,800) (132,532) (127,987) Proceeds From Sales and Leaseback Transactions and other 730 10.84 1. 560 Net cash Flows used For Investing Activities (136,070) (121.691) (126.427) FINANCING ACTIVITIES: change in Advances from Affiliates (net) (212,641) 92,652 88,732 Issuance of Affiliated Long-term Debt 160,000 200,000 Retirement of Preferred Stock (10,000) (5,000) (10,000) Retirement of General Long-term Debt (133,343) (314,733) (25,274) Retirement of Affiliated Long-term Debt (200,000) Change in short-term Debt (net) 290,000 (45,500) Dividends Paid on Common Stock (65,300) (82,952) (240,600) Dividends Paid on Cumulative Preferred Stock (525) (962) (1.575) Net cash Flows used For Financing Activities (171 809) (110.995) (234,217) Net Increase (Decrease) in cash and cash Equivalents (10,879) 758 6,946 Cash and cash Equivalents January 1 12.358 11,600 4.654 cash and Cash Equivalents December 31 3- 1 "79 S-1 3-5-8 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 $ 847.664 S 791.493 PREFERRED STOCK:. S100 par value authorized shares 2,500,000 525 par value - authorized shares 7,000,000 shares Number of shares Redeemed outstanding series Year Ended December 31, December 31, 2002 2002 2001 2000 Subject to Mandatory Redemption: 7.00% 100,000 50,000 100,000 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 222,797 243,197 Installment Purchase Contracts 91,275 91,220 Senior unsecured Notes 147,554 147,458 Notes Affiliated 160,000 200,000 Junior Debentures 109,973 Less Portion Due within one Year ( 43.000) (220. 500) Total Long-term Debt Excluding Portion Due within one Year 578.626 571. 348 TOTAL CAPITALIZATION S1L 42,9 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 Senior unsecured notes outstanding were as follows: follows: December 31, 2002 2001 December 31. (in thousands) 2002 2001 % Rate Due (in thousands) 7.25 2002 October 1 S - $ 14,000 % Rate Due 7.15 2002 November 1 6,500 6.85 2005 October 3 $ 36,000 S 36,000 6.80 2003 May 1 13,000 13,000 6.51 2008 February 1 52,000 52,000 6.60 2003 - August 1 25,000 25,000 6.55 2008 June 26 60,000 60,000 6.10 2003 November 1 5,000 5,000 unamortized Discount (446) (542) 6.55 2004 March 1 26,500 26, 500 Total 6.75 2004 May 1 26,000 26,000 8.70 2022 July 1 2,000 2,000 8.55 2022 August 1 15,000 15,000 Notes payable to parent company were as 8.40 8.40 2022 2022 August 15 October 15 14,000 13,000 14,000 13,000 follows: December 31, 7.90 2023 May 1 40,000 40,000 2002 2001 7.75 2023 August 1 33,000 33,000 (in thousands) 7.60 2024 May 1 11,000 11,000 % Rate Due unamortized Discount (703) (803) (a) 2002 - Sept 25 S - $200,000 Total 6.501% 2006 May 15 160.000 Total S160,00 First mortgage bonds are secured by a first (a) Redemed 9/25/02 mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage Junior debentures outstanding were as lien contain maintenance and replacement follows: provisions requiring the deposit of cash or December 31, 2002 2001 bonds with the trustee, or in lieu thereof, (in thousands) certification of unfunded property additions. % Rate Due 8-3/8 2025 Sept 30 S - S 72,843 7.92 2027 March 31 - 40,000 Installment purchase contracts have been unamortized Discount - (2.870) Total 5~ entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: At December 31, 2002, future annual long-December 31, term debt payments are as follows: 2002 2001 (in thousands) Amount % Rate Due (in thousands) 6-3/8 2020 - December 1 $48,550 $48,550 2003 S 43,000 6-1/4 2020 - December 1 43,695 43,695 2004 52,500 unamortized Discount (970) (1.02 5) 2005 36,000 Total 191,m 2006 160,000 2007 Later Years 332.245 Under the terms of the installment purchase Total Principal Amount 623,745 contracts, CSPCo is required to pay amounts unamortized Discount (2.119) Total 5621 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. combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 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 Asset Impairments 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 supplementary Information Note 20 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 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 AND SUBSIDIARIES Selected Consolidated Financial Data Yeair Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,526,764 $1, 526,997 $1,488,209 $1,351,666 $1,405,794 operating Expenses 1.375,575 1.367,292 1.522.911 1.243,014 1,239,787 operating Income (Loss) 151, 189 159,705 (34,702) 108,652 166,007 Nonoperating Items, Net 16,726 9,730 9,933 4,530 (839) Interest charges 93.923 93. 647 107. 263 80.406 68.540 Net Income (Loss) 73,992 75,788 (132,032) 32,776 96,628 Preferred stock Dividend Requirements 4.601 4.621 4,885 4.824 Earnings (Loss) Applicable to Common stock $ 71,167 $ 27,891 December 31, _ _ _ _ 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric utility Plant $5,029,958 $4,923,721 $4,871,473 $4,770,027 $4,631,848 Accumulated Depreciation and Amortization 2,568.604 2.436.972 2.280.521 2.194.397 2.081, 355 Net Electric Utility Plant $2,.461,3~54 $2,486, 749 $2.,590.,952 $2,5575,30 $2.,550.,493 Total Assets i48L28719 common stock and Paid-in capital $ 915,144 $ 789,800 $ 789,656 $ 789,323 $ 789,189 Accumulated other comprehensive Income (LoSS) (40,487) (3,835) Retained Earnings 143.996 74,605 3,443 166.389 2 53.154 Total Common shareholder's Equity $108,11 $ 8,36 S 793,0996 $ 9,552, $1 273 cumulative Preferred stock: Not subject to Mandatory Redemption S 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 subject to Mandatory Redemption (a) 64.945 64, 945 64,945 64.945 68.445 Total Cumulative Preferred stock $163,046 $£ 74.193 $ 7-7.718 Long-term Debt (a) $1, 617,062 11,652-Q&Z $1,388,939 $1,324, 3-26 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 maintenance costs incurred as part of generation, purchase, sale, transmission and planned and unplanned outages at Cook distribution of electric power to 571,000 retail Plant and Rockport Plant. customers in its service territory in northern and eastern Indiana and a portion of During 2000 both of the Cook Plant nuclear southwestern Michigan. As a member of the units were successfully restarted after being AEP Power Pool, I&M shares the revenues shutdown in September 1997 due to and the costs of the AEP Power Pool's questions regarding the operability of certain wholesale sales to neighboring utilities and safety systems which arose during a NRC power marketers. I&M also sells wholesale architect engineer design inspection (see power to municipalities and electric Note 5). cooperatives. As a result of costs incurred in 2000 to restart The cost of the AEP Power Pool s generating the Cook Plant and a disallowance of interest capacity is allocated among its members deductions for a corporate owned life based on their relative peak demands and insurance (COLI) program, Net Income generating reserves through the payment of increased in 2001 by $208 million. In capacity charges and the receipt of capacity February 2001 the U.S. District Court for the credits. AEP Power Pool members are also Southern District of Ohio ruled against AEP compensated for the out-of-pocket costs of and certain of its subsidiaries, including l&M, energy delivered to the AEP Power Pool and in a suit over deductibility of interest claimed charged for energy received from the AEP in AEP s consolidated tax return related to Power Pool. The AEP Power Pool calculates COLI. In 1998 and 1999 I&M paid the each company's prior twelve month peak disputed taxes and interest attributable to the demand relative to the total peak demand of COLI interest deductions for the taxable years all member companies as a basis for sharing 1991-98 and deferred them. The deferrals revenues and costs. The result of this were expensed and impacted Net Income in calculation is each company's member load 2000. ratio (MLR) which determines each company's percentage share of revenues and costs. Operatina Revenues Increase Under unit power agreements, I&M Operating Revenues were flat in 2002 and purchases AEGCo's 50% share of the 2,600 increased 3% in 2001. The 2001 increase MW Rockport Plant capacity unless it is sold reflects increased sales to AEP affiliates to other utilities. AEGCo is an affiliate that is through the AEP Power Pool. The following not a member of the AEP Power Pool. An analyzes the changes in Operating Revenues: agreement between AEGCo and KPCo Increase (Decrease) provides for the sale of 390 MW of AEGCo s From Previous Year (dollars in milions) Rockport Plant capacity to KPCo through 2002 2001 2004. The KPCo agreement extends until Amount % Amount % December 31, 2009 for Rockport Unit I and Retail* $ 28.2 4 S (2.3) N.M until December 7, 2022 for Rockport Plant Marketing 2.6 1 (12.0) (4) other 2.6 6 5 .0 13 Unit 2 if AEP s restructuring settlement Total wholesale agreement filed with the FERC becomes Electricity 33.4 3 (9.3) (1) operative. Therefore, l&M purchases 910 MW Energy of AEGCo's 50% share of Rockport Plant Dellvery* 7.3 2 3.4 1 capacity. sales to AEP Affiliates (40 ) (16) 44.7 21 Total ) N.M. 3.3 3 Results of Operations N.M. = Not Meaningful
*Reflects the allocation of certain During 2002 Net Income decreased by $2 transmission and distribution revenues million due to increased operations and included in bundled retail rates to energy delivery.
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The increase in Operating Revenues in 2001 Plant nuclear units for restart with their return is primarily due to increased sales to AEP to service in 2000. Maintenance expense affiliates reflecting increased availablility of the increased for nuclear maintenance costs Cook Plant. The return to service of the Cook incurred during refueling outages in 2002. Plant units increased the amount of power l&M could sell to its affiliates in the AEP The increase in Depreciation and Power Pool. Amortization charges in 2001 reflects increased generation and distribution plant Operating Expenses investments and amortization of l&M s share of deferred merger costs. Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 Due to a change in the Indiana property tax decrease was primarily due to the unfavorable law which lowered the floor percentage for COLI tax ruling and costs related to the calculating tax liability, Taxes Other Than extended Cook Plant outage and restart Income Taxes declined in 2002. Taxes Other efforts in 2000. The changes in the than Income Taxes increased in 2001 due to components of Operating Expenses were: higher real and personal property tax expense from the effect of a favorable accrual Increase (Decrease) From Previous Year adjustment of amounts recorded in December (dollars in millions) 2000 to actual expenses. 2002 2001 Amount % Amount % Income Taxes attributable to operations Fuel I'0(10.6) (4) $ 39.2 19 wholesale decreased in 2002 due to a decrease in pre-Electricity Purchases 4.7 25 4.9 36 tax operating income. The significant AEP Affiliate increase in Income Taxes attributable to Purchases (4.5) (2) (27.2) (10) operations in 2001 is due to an increase in Other operation 13.6 3 (147.7) (25) Maintenance 24.3 19 (92.6) (42) pre-tax operating income. Depreciation and Amortization 3.8 2 9.3 6 Taxes other Than Nonoperating Income. Nonoperating Income Taxes (7.8) (12) 4.9 8 Income Taxes (15.2) (28) 53.6 N.M. Expenses and Income Taxes Total I w-- 1 ) (10) N.M. = Not Meaningful The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains Fuel expense decreased in 2002 due to lower on forward electricity trading transactions average costs of fuel and a decline in nuclear outside AEP s traditional marketing area. The generation. The increase in Fuel expense in increase in Nonoperating Income in 2001 is 2001 reflects an increase in nuclear primarily due to increased net gains on generation as the Cook Plant units returned to forward electricity trading transactions outside service following the extended outage. AEP s traditional marketing area. Wholesale Electricity purchases increased in Nonoperating Expenses decreased in 2002 2002 and 2001 due to increased purchases due to decreased trading overheads and from third parties for sales for resale. AEP traders incentive compensation. Affiliates purchases declined in 2002 due to Nonoperating Expenses increased in 2001 lower purchases from AEGCo at lower costs. due to increased trading overheads and The decline in purchased power from AEP traders incentive compensation. affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP The increase in Nonoperating Income Taxes Power Pool which declined 21 %. in 2001 reflects the increase in nonoperating pre-tax income. Other Operation expense increased in 2002 primarily due to higher costs for pensions, Interest Charges other benefits and insurance. The decrease in Other Operation and Maintenance The decrease in 2001 Interest Charges expenses in 2001 was primarily due to the reflects the recognition in 2000 of deferred cessation of expenditures to prepare the Cook 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 $ 990,905 $ 957,548 $ 966,882 Energy Delivery 321,721 314,410 311,019 Sales to AEP Affiliates 214,138 255.039 210.308 TOTAL OPERATING REVENUES 1. 526. 764 1,526.997 1.488.209 OPERATING EXPENSES: Fuel 239,455 250,098 210,870 Purchased Power: wholesale Electricity 23,443 18,707 13,785 AEP Affiliates 233,724 238,237 265,475 other operation 462,707 449,115 596,861 Maintenance 151,602 127,263 219,854 Depreciation and Amortization 168,070 164,230 154,920 Taxes other Than Income Taxes 57,721 65,518 60,622 Income Taxes 38. 853 54.124 524 TOTAL OPERATING EXPENSES 1. 375. 575 1.367,292 1.522.911 OPERATING INCOME (LOSS) 151,189 159,705 (34,702) NONOPERATING INCOME 93,739 97,810 76,499 NONOPERATING EXPENSES 71,029 83,037 62,377 NONOPERATING INCOME TAXES 5,984 5,043 4,189 INTEREST CHARGES 93. 923 93 647 107.263 NET INCOME (LOSS) 73,992 75,788 (132,032) PREFERRED STOCK DIVIDEND REQUIREMENTS 4.601 4.621 4,624 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK S 71,167 $ 315,2656) Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME (LOSS) $ 73,992 $75,788 $(132,032) OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 3,835 (3,835) Cash Flow Power Hedge (286) Minimum Pension Liability (40,201)
-Z2 COMPREHENSIVE INCOME (LOSS) $ 37, 5113Z-02) see Notes to Financia7 statements beginning on page L-1.
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INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31. 2002 2001 2000 (in thousands) Retained Earnings January 1 $ 74,605 S 3,443 $ 166,389 Net Income (Loss) 73, 992 75.788 (132.032) 148, 597 - 79.231 34. 357 Deductions: cash Dividends Declared: Common stock 26,290 cumulative Preferred stock: 4-1/8% series 229 229 230 4.56% Series 66 66 66 4.12% series 52 72 74 5.90% series 897 897 897 6-1/4% series 1,203 1,203 1,203 6.30% series 834 834 834 6-7/8% series 1.186 1.186 1,186 Total Cash Dividends Declared 4,467 4,487 30,780 capital stock Expense 134 139 134 Total Deductions 4.601 4.626 30.914 Retained Earnings December 31 $143 S 74,6L05 $3 1A443 See Notes to Financia7 statements beginning on page L-1. G-6
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31. 2002 2001 (in thousand S) ASSETS ELECTRIC UTILITY PLANT: Production $2,768,463 $2,758,160 Transmission 971,599 957,336 Distribution 921,835 900,921 General (including nuclear fuel) 220,137 233,005 Construction work in Progress 147.924 74.299 Total Electric Utility Plant 5,029,958 4,923,721 Accumulated Depreciation and Amortization 2.568,604 2,436.972 NET ELECTRIC UTILITY PLANT 2.461. 354 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 120,941 127.977 CURRENT ASSETS: cash and cash Equivalents 3,237 16,804 Advances to Affiliates 191,226 46,309 Accounts Receivable: Customers 67,333 60,864 Affiliated Companies 122,489 31,908 Miscellaneous 30,468 25,398 Allowance for uncollectible Accounts (578) (741) Fuel 32,731 28,989 Materials and Supplies 95,552 91,440 Energy Trading and Derivative Contracts 68,148 108,895 Accrued Utility Revenues 6,511 2,072 Prepayments and other 11,899 6.497 TOTAL CURRENT ASSETS 629.016 418.435 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 $ 56,584 $ 56,584 Paid-in Capital 858,560 733,216 Accumulated other Comprehensive Income (Loss) (40,487) (3,835) Retained Earnings 143 996 74.605 Total Common shareholder's Equity 1,018,653 860,570 cumulative Preferred Stock: Not subject to Mandatory Redemption 8,101 8,736 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1.587,062 1.3123082 TOTAL CAPITALIZATION 2,678, 761 2.246. 333 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 620,672 600,244 other 138.965 87,025 TOTAL OTHER NONCURRENT LIABILITIES 759.637 687,269 CURRENT LIABILITIES: Long-term Debt Due within one Year 30,000 340,000 Accounts Payable General 125,048 86,766 Accounts Payable - Affiliated Companies 93,608 43,956 Taxes Accrued 71,559 69,761 Interest Accrued 21,481 20,691 obligations under capital Leases 8,229 10,840 Energy Trading and Derivative Contracts 48,568 93,413 other 92. 822 76 486 TOTAL CURRENT LIABILITIES 491,315 741.913 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 REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 92,039 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 2000 (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $ 73,992 $ 75,788 $ (132,032) Adjustments for Noncash Items: Depreciation and Amortization 168,070 166,360 163,391 Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net) (26,577) 418 5,737 Amortization of Nuclear Outage Costs 40,000 40,000 40,000 Deferred Income Taxes (16,921) (29,205) (125,179) Deferred Investment Tax credits (7,740) (8,324) (7,854) Unrecovered Fuel and Purchased Power Costs 37,501 37,501 37,501 Changes in Certain Current Assets And Liabilities: Accounts Receivable (net) (102,283) 64,841 (25,305) Fuel, Materials and Supplies (7,854) (19,426) 10,743 Accrued utility Revenues (4,439) (2,072) 44,428 Accounts Payable 87,934 (60,185) 85,056 Taxes Accrued 1,798 1,345 19,446 Mark-to-Market of Energy Trading and Derivatives Contracts (9,517) (62,647) 14,830 Disputed Tax and Interest Related to COLI 56,856 Regulatory Asset Trading Losses (992) 8,493 (17,914) Regulatory Liability Trading Gains 2,494 34,293 (7,416) change in other Assets (28,233) (5,871) (68,160) Change in other Liabilities 21.001 (5,102) 37.309 Net cash Flows From Operating Activities 228.234 236,207 131.437 INVESTING ACTIVITIES: Construction Expenditures (167,484) (91,052) (171,071) Bu yout of Nuclear Fuel Leases (92,616) Other 1. 759 1,074 587 Net Cash Flows Used For Investing Activities (165 .72 5) (182.594) (170.484) FINANCING ACTIVITIES: capital Contributions from Parent Company 125,000 Issuance of Long-term Debt 288,732 297,656 199,220 Retirement of cumulative Preferred Stock (424) (314) Retirement of Long-term Debt (340,000) (44,922) (148,000) change in Advances from Affiliates (net) (144,917) (299,891) 253, 582 change in short-term Debt (net) (224,262) Dividends Paid on Common stock (26,290) Dividends Paid on cumulative Preferred stock (4.467) (4.487) (3. 368) Net cash Flows From (Used For) Financing Activities (76.076) (51.644) . 50. 568 Net Increase (Decrease) in cash and cash Equivalents (13,567) 1,969 11,521 cash and Cash Equivalents January 1 16.804 14.835 3,314 cash and cash Equivalents December 31 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) COMMON SHAREHOLDER S EQUITY $1.018.653 S 860.570 PREFERRED STOCK: $100 Par value - Authorized 2,250,000 shares $25 Par value - Authorized 11,200,000 shares 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-$100 Par: 4-1/8% 106.125 20 - 3,750 55,369 5,537 5,539 4.56% 102 - - - 14,412 1,441 1,441 4.12% 102.728 6,326 - 1,375 11,230 1.123 i1. 756 8.101 8.736 Subject to Mandatory Redemption-S100 Par(b): 5.90% (c) - - - 152,000 15,200 15,200 6-1/4% (c) - - - 192,500 19,250 19, 250 6.30% (c) - - - 132,450 13,245 13,245 6-7/8% (d) - - - 172,500 17.250 174950 64.945 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 SZ,2A33 4S2j1 (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 The terms of* the installment purchase follows: contracts require l&M to pay amounts December 31. 2002 2001 sufficient for the cities to pay interest on and (in thousands) the principal of (at stated maturities and upon % Rate Due 7.60 2002 November 1.S $ 50,000 mandatory redemptions) related pollution 7.70 2002 December 15- 40,000 control revenue bonds issued to finance the 6.10 2003 - November 1 30,000 30,000 8.50 2022 - December 15 75,000 75,000 construction of pollution control facilities at 7.35 7.20 2023 2024 October 1 February 1 15,000 30,000 15,000 30,000 certain generating plants. The term rate 7.50 2024 March 1 25.000 25,000 bonds due 2025 are subject to mandatory unamortized Discount (75 5) (859) tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate First mortgage bonds are secured by a first bonds have been classified for repayment mortgage lien on electric utility plant. Certain purposes in 2007 (the term end date). supplemental indentures to the first mortgage lien contain maintenance and replacement Senior unsecured notes outstanding were as provisions requiring the deposit of cash or follows: December 31. bonds with the trustee, or in lieu thereof, 2002 2001 certification of unfunded property additions. (in thousands)
% Rate Due (a) 2002 September 3 S - $200,000 6-7/8 2004 3uqy 1 150,000 150,000 Installment purchase contracts have been 6.125 2006 December 15 300,000 300,000 entered in connection with the issuance of 6.45 2008 November 10 50,000 50,000 6.375 2012 November 1 100,000 pollution control revenue bonds by 6 2032 December 31 150,000 governmental authorities as follows: unamortized Discount (2.973)
S7AL02 (3.856) December 31. (a) A floating interest rate was determined 2002 2001 quarterly. The rate on December 31, 2001 (in thousands) was 2.71%. The average interest rates were % Rate Due 2.6% in 2002 and 5.1% in 2001. City of Lawrenceburg, Indiana: 7.00 2015 April 1 S 25,000 S 25,000 5.90 2019 - November 1 52,000 52,000 Junior debentures outstanding were as city of Rockport, Indiana: follows: (a) 2014 August 1 50,000 December 31. 7.60 2016 March 1 40,000 40,000 2002 2001 6.55 2025 June 1 50,000 50,000 -in thousands) (b) 2025 June 1 50,000 50,000 % Rate Due 4.90(c) 2025 June 1 50,000 8.00 2026 March 31 S 40,000 S 40,000 7.60 2038 June 30 125,000 125,000 city of Sullivan, Indiana: unamortized Discount (3 282) (3.389) 5.95 2009 May 1 45,000 45,000 Total S161 71 unamortized Discount (1.664) (1 761) I1t3036 S1 3 Interest may be deferred and payment of (a) A variable interest rate was determined principal and interest on the junior debentures weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001. is subordinated and subject in right to the (b) In June 2001 an auction rate was prior payment in full of all senior indebtedness established. Auction rates are determined by standard procedures every 35 days. The of I&M. 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 At December 31, 2002, future annual long-1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate term debt payments are as follows: was a daily, weekly, commercial paper or Amount term rate as designated by I&M. A weekly (in thousands) rate was selected which ranged from 1.9% 2003 S 30,000 to 4.9% in 2001 and averaged 3.3% during 2004 150,000 2001. 2005 (c) Rate is fixed until June 1, 2007 (term 2006 300,000 rate bonds). 2007 50,000 Later Years 1.095.736 Total Principal Amount 1,625,736 unamortized Discount (8.674) Total 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. Combined Footnote Reference significant Accounting Policies Note 1 Merger Note 4 Nuclear Plant Restart Note 5 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 Asset Impairments 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 Supplementary Information Note 20 Leases Note 22 Lines of credit and Sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Related Party Transactions 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 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 378,683 $ 379,025 $ 389,875 $ 358,757 $ 362,999 Operating Expenses 336.486 331. 347 340.137 304.082 311.106 Operating Income 42,197 47,678 49,738 54,675 51,893 Nonoperating Items, Net 5,206 1,248 2,070 (327) (1,726) Interest Charges 26.836 27. 361 31.045 28.918 28.491 Net Income $ 20,567 $ 21,565 20,76i3 $ 2iA3A0 kS _21,676 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric utility Plant $1,295,619 $1,128,415 $1,103,064 $1,079,048 $1,043,711 Accumulated Depreciation and Amortization 397, 304 384.104 360.648 340.008 315. 546 Net Electric Utility Plant $ 744,311 S 742,416 $ 739.040 $ 728 165 Total Assets $1,164,676 S 999,048 $1,494,543 $ 986.123 $ 921,3A7 Common Stock and Paid-in Capital $ 259,200 $ 209,200 $ 209,200 $ 209,200 $ 199,200 Accumulated Other comprehensive Income (LoSS) (9,451) (1,903) Retained Earnings 48.269 57.513 67.110 71.,452 Total Common shareholder's Equity Si248 0-18 S_266,713 $ 2 6,310 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, Results of Operations purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in Net Income for 2002 decreased $1 million or 5%. eastern Kentucky. KPCo as a member of the Total Revenues were flat while increases in AEP Power Pool shares in the revenues and Operating Expenses, driven by expenses related costs of the AEP Power Pool's wholesale sales to to planned outages at the Big Sandy plant, were neighboring utility systems and power marketers offset by comparable gains in net nonoperating including power trading transactions. KPCo also income which benefited from decreases in trading sells wholesale power to municipalities. incentive compensation. The cost of the AEP Power Pool's generating Changes in Revenues capacity is allocated among the Pool members based on their relative peak demands and Increase (Decrease) generating reserves through the payment of Year-to-Date (dollars in milions capacity charges and the receipt of capacity Amount % credits. AEP Power Pool members are also wholesale Electricity* $13 6 Energy Delivery* compensated for their out-of-pocket costs of Sales to AEP Affiliates j!) C(34) Total energy delivered to the AEP Power Pool and charged for energy received from the AEP Power *Reflects the allocation of certain transmission and distribution revenues included in bundled Pool. The AEP Power Pool calculates each retail rates to energy delivery. company's prior twelve month peak demand relative to the total peak demand of all member Revenues in 2002 were comparable to those of companies as a basis for sharing revenues and last year. Increased sales to retail electricity costs. The result of this calculation is the member customers reflecting warmer summer weather, load ratio (MLR) which determines each colder days in late 2002, and increased fuel company's percentage share of AEP Power Pool recovery revenues were offset by lower Sales to revenues and costs. AEP Affiliates resulting from planned outages in 2002. KPCo s decreased generation was due to KPCo has a unit power agreement with AEGCo, scheduled maintenance resulting in lower an affiliated company, which expires in 2004. The availability in the fourth quarter. unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until Changes in Operating Expenses December 7, 2002 for Rockport Plant Unit 2 if AEP s settlement restructuring agreement filed Increase (Decrease) with the FERC becomes operative. The Year-to-Date agreement provides for KPCo to purchase 15% of (dollars in millions) Amount % the total output of the two unit 2,600-mw capacity Rockport Plant. Underthe unit power agreement, Fuel S(5.6) (8) wholesale Electricity - N.M. there is a demand charge for the right to receive Purchases from AEP Affiliates 2.8 2 the power, which is payable even it the power is other operation (5.4) (9) not taken. The amount of the demand charge is Maintenance 12.6 56 Depreciation .7 2 such that when added to other amounts received Taxes other Than by AEGCo, it will enable AEGCo to recover all its Income Taxes .4 5 fixed expenses including a FERC-approved rate Income Taxes Total Operating Expenses
-E4) (4) 2 of return on common equity. N.M. = Not Meaningful 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 Nonoperating Income Taxes for 2002 have megawatt Unit 2, representing approximately 75% increased as a result of increases in pre-tax of the plants generation capacity, was off-line income for the year offset in part by prior-year tax from mid-September through the end of the year, return adjustments. thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 Other Changes increased to meet demand during the planned outages at the Big Sandy plant. Nonoperating Income for 2002 decreased as a result of AEP s previously announced plan to Other Operation expense decreased in 2002 due reduce trading activity, and decreased margins on to reduced consumption of emission allowances power trading activity outside of the AEP due to the planned outage; reduced accruals for System s traditional marketing area resulting from trading incentive compensation due to reduced soft market demand. Nonoperating Expenses trading activity; and improvements intransmission decreased in 2002 as a result of decreases in expense resulting from less wholesale activity and trading incentive compensation. 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). Maintenance expense increased in2002 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 Ended December 31. 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $218,665 $205,476 $226,708 Energy Delivery 132,054 131,183 121,346 Sales to AEP Affiliates 27,964 42. 366 41.821 TOTAL OPERATING REVENUES 378.683 379.02 5 389,875 OPERATING EXPENSES: Fuel 65,043 70,635 74,638 Purchased Power: wholesale Electricity 29 86 1,940 AEP Affiliates 133,002 130,204 127,707 other operation 52,892 58,275 52,495 Maintenance 35,089 22,444 25,866 Depreciation and Amortization 33,233 32,491 31,028 Taxes other Than Income Taxes 8,240 7,854 7,251 Income Taxes 8.958 9. 358 19,212 TOTAL OPERATING EXPENSES 336,486 331, 347 340.137 OPERATING INCOME 42,197 47,678 49,738 NONOPERATING INCOME 7,863 10,881 6,139 NONOPERATING EXPENSES 753 8,949 2,940 NONOPERATING INCOME TAXES 1,904 684 1,129 INTEREST CHARGES 26,836 27. 361 31.045 NET INCOME 20.567 La25=U6 L 20,76 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME $ 20,5b7 $21,565 $20,763 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 2,225 (1,903) Minimum Pension Liability (9.773) COMPREHENSIVE INCOME $1 3, ol Statements of Retained Earnings Year Ended December 31. 2002 2001 2000 (in thousands) RETAINED EARNINGS JANUARY 1 $48,833 $57,513 $67,110 NET INCOME 20,567 21,565 20,763 CASH DIVIDENDS DECLARED 21,131 30.245 30.360 RETAINED EARNINGS DECEMBER 31 $A& See Notes to Financial statements beginning on page L-1. H4
KENTUCKY POWER COMPANY Balance Sheets December 31. 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 275,121 S 271,070 Transmission 373,639 374,116 Distribution 425,817 402,537 General 55,913 65,059 Construction Work in Progress 165.129 15.633 Total Electric Utility Plant 1,295,619 1,128,415 Accumulated Depreciation and Amortization 397.304 384.104 NET ELECTRIC UTILITY PLANT 898.315 744.311 OTHER PROPERTY AND INVESTMENTS 6.904 6,492 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 29.871 29.477 CURRENT ASSETS: Cash and Cash Equivalents 2,304 1,947 Accounts Receivable: Customers 22,044 20,036 Affiliated Companies 23,802 16,012 Miscellaneous 2,889 3,333 Allowance for uncollectible Accounts (192) (264) Fuel 10,817 12,060 Materials and supplies 16,127 15,766 Accrued Utility Revenues 5,301 5,395 Accrued Tax Benefit 1,253 Energy Trading Contracts 24,320 33,905 Prepayments and other 2,127 1,314 TOTAL CURRENT ASSETS 110,792 109,504 REGULATORY ASSETS 101,976 97.692 DEFERRED CHARGES 16.818 11,572 TOTAL ASSETS $1,164,676 SL999,048 see Notes to Financial statements beginning on page L-1. 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 S 50,450 $ 50,450 Paid-in Capital 208,750 158,750 Accumulated other Comprehensive Income (Loss) (9,451) (1,903) Retained Earnings 48.269 48.833 Total Common Shareowner S Equity 298,018 256,130 Long-term Debt 391,632 176,093 Long-term Debt Affiliated Companies 60.000 75,000 TOTAL CAPITALIZATION 749,650 507. 223 OTHER NONCURRENT LIABILITIES 27. 319 11.929 CURRENT LIABILITIES: Long-term Debt Due within One Year - General 95,000 Long- term Debt Due within one Year - Affiliated Companies 15,000 Advances from Affiliates 23,386 66,200 Accounts Payable: General 46,515 23,464 Affiliated Companies 44,035 22,557 Customer Deposits 8,048 4,461 Taxes Accrued 10,305 Interest Accrued 6,471 5,269 Energy Trading and Derivative Contracts 17,803 38,664 other 14. 322 12,882 TOTAL CURRENT LIABILITIES 175. 580 278,802 DEFERRED INCOME TAXES 178,313 168,304 DEFERRED INVESTMENT TAX CREDITS 9,165 10,405 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 11.488 14,917 REGULATORY LIABILITIES AND DEFERRED CREDITS 13.161 7,468 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES S1,164,676 See Notes to Financial statements beginning on page L-1. H-6
KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $ 20,567 $ 21,565 $ 20,763 Adjustments for Noncash Items: Depreciation and Amortization 33,233 32,491 31,034 Deferred Income Taxes 9,839 6,293 3,765 Deferred Investment Tax credits (1,240) (1,251) (1,252) Deferred Fuel Costs (net) 2,998 (4,707) 2,948 Mark-to-Market of Energy Trading Contracts (12,267) (1,454) (4,376) change in Certain Current Assets and Liabilities: Accounts Receivable (net) (9,426) 23,694 (20,930) Fuel, Materials and supplies 882 (7,658) 8,386 Accrued Utility Revenues 94 1,105 7,237 Accounts Payable 44,529 (22,942) 39,883 Taxes Accrued (11,558) (1,580) 2,025 Disputed Tax and Interest Related to COLI .5,943 Change in other Assets (21,491) (2,762) 62,653 change in other Liabilities 16.161 (9,446) (62. 702) Net cash Flows From Operating Activities 72, 321 33, 348 95, 377 INVESTING ACTIVITIES: construction Expenditures (178,700) (37,206) (36,209) Proceeds From Sales of Property 217 216 266 Net Cash Flows Used For Investing Activities (178,483) (36 990) (35.943) FINANCING ACTIVITIES: capital contributions from Parent Company 50,000 Issuance of Long-term Debt 274,964 75,000 69,685 Retirement of Long-term Debt (154, 500) (60,000) (105,000) change in short-term Debt (net) (39,665) change in Advances From Affiliates (net) (42,814) 18,564 47,636 Dividends Paid (21.131) (30,245) (30 ,360) Net cash Flows From (used For) Financing Activities 106,519 3, 319 (57.704) Net Increase (Decrease) in cash and cash Equivalents 357 (323) 1,730 cash and cash Equivalents January 1 1$947 2,270 540 cash and cash Equivalents December 31 3-2.3-04 $ 1,947
- 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) COMMON SHAREHOLDER S EQUITY $298.018 $256.130 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 59,383 Senior unsecured Notes 352,508 147,625 Notes Payable 75,000 100,000 Junior Debentures 39,124 39,085 Less Portion Due within one Year (15.000) (95.000) Long-term Debt Excluding Portion Due within one Year 451.632 251.093 TOTAL CAPITALIZATION $7A9,6iQ 5507.2_2 See Notes to Financia7 statements beginning on page L-1. H-8
KENTUCKY POWER COMPANY Schedule of Lonq-term Debt First mortgage bonds outstanding were as Notes payable to banks outstanding were as follows: follows: December 31. 2002 2001 December 31. (in thousands) 2002 2001 % Rate Due (in thousands) 6.65 2003 May 1 S S 15,000 X Rate Due 6.70 2003 June 1 15,000 7.45 2002 September 20 S =- 6.70 2003 July 1 15,000 7.90 2023 June 1 14,500 Unamortized Discount il 17) Junior debentures outstanding were as follows: First mortgage bonds were secured by a first December 31, 2002 2001 mortgage lien on electric utility plant. (in thousands)
% Rate Due 8.72 2025 June 30 540,000 $40,000 Senior unsecured notes outstanding were as unamortized Discount (876) (915) follows: Total 539,12 539 08 December 31. Interest may be deferred and payment of 2002 2001 principal and interest on the junior debentures (in thousands)
% Rate Due is subordinated and subject in right to the (a) 2002 - November 19 S - S 70,000 6.91 2007 October 1 48,000 48,000 prior payment in full of all senior indebtedness 6.45 5.50 2008 2007 November 10 July 30,000 125,000 30,000 of the Company. 4.31 2007 November 12 80,400 - 4.37 2007 December 12 69,564 - At December 31, 2002, future annual long-unamortized Discount (456) (375) S3258S4,Z term debt payments are as follows: (a) A floating interest rate is determined Amount monthly. The rate December 31, 2001 was (in thousands) 4.3%. 2003 S 15,000 2004 Notes payable to parent company were as 2005 2006 60,000 follows: 2007 322,964 Later Years 70.000 December 31. Total Principal Amount 467,964 2002 2001 unamortized Discount (1.332) (in thousands) Total S466,-632 % Rate Due 4.336 2003 May 15 $15,000 S15,000 6.501 2006 May 15 60.000 60.000 S75,00 57,0 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. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Asset Impairments 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 Related Party Transactions 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 inthe 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. Inour 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 inthe 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 Year Ended December 3 . 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $2,113,125 $2,098,105 $2,140,331 $1,978,826 $2,105,547 operating Expenses 1.814,796 1.857, 395 1.913. 504 1.689.997 1,816.175 operating Income 298,329 240,710 226,827 288,829 289,372 Nonoperating Items, Net 5,376 18,686 (5,004) 7,000 588 Interest charges 83. 682 93.603 119,210 83.672 80,035 Income Before Extraordinary Item 220,023 165,793 102,613 212,157 209,925 Extraordinary Loss (18. 348) (18.876) Net Income 220,023 147,445 83,737 212,157 209,925 Preferred Stock Dividend Requirements 1.258 1.258 1.266 1,417 1.474 Earnings Applicable To Common stock $ 146,187 $ 82,471 LI210,740 L 20845 December 31, - A -A -- - - 2002 2001 2000 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,685,826 $5,390,576 $5,577,631 $5,400,917 $5,257,841 Accumulated Depreciation 2.566.828 2.452 571 2.764.130 2.621.711 2,461.376 Net Electric utility Plant $4.457.032,93SiIM $2.813 .50 $2 779,206 $2,796,465 Total Assets 361397.5 $4.675,5 $4,344,68 Common stock and Paid-in Capital $ 783,684 $ 783,684 $ 783,684 $ 783,577 $ 783,536 Accumulated other comprehensive Income (LoSS) (72,886) (196) Retained Earnings 522.316 401.297 398.086 587.424 587. 500 Total Common Shareholder's Equity S1A8181Z0 Cumulative Preferred stock: Not subject to Mandatory Redemption $ 16,648 $ 16,648 $ 16,648 $ 16,937 $ 17,370 subject to Mandatory Redemption (a) 8.850 8.850 8.850 8.850 11,850 Total Cumulative Preferred stock $ 2549 Long-term Debt (a) $1,067,314 SZ5__M25.4982~2~ obligations under capital Leases (a) $&65,_626 S fL8--6&66 t$A__42, 635 Total capitalization and Liabilities $4,457,03 $6.193,975 $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 of Ohio ruled against AEP and certain of its utility engaged in the generation, purchase, subsidiaries, including OPCo, in a suit over sale, transmission and distribution of electric deductibility of interest claimed in AEP s power to 702,000 retail customers in consolidated tax returns related to COLI. In northwestern, east central, eastern and 1998 and 1999 OPCo paid the disputed taxes southern sections of Ohio. OPCo supplies and interest attributable to the COLI interest electric power to the AEP Power Pool and deductions for taxable years 1991-98. The shares the revenues and costs of the AEP payments were included in Other Property Power Pool's wholesale sales to neighboring and Investments pending the resolution of this utility systems and power marketers including matter. Net Income was also favorably power trading transactions. OPCo also sells impacted by the growth in and strong wholesale power to municipalities and performance by the wholesale business. The cooperatives. effects of the COLI decision in 2000 and favorable wholesale business in 2001 were The cost of the AEP Power Pool's generating offset in part by the commencement of the capacity is allocated among Pool members amortization of transition regulatory assets in based on their relative peak demands and 2001, the effect of mild winter weather and generating reserves through the payment of the economic downturn. capacity charges or the receipt of capacity credits. AEP Power Pool members are also Operating Revenues compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and Operating Revenues increased 1% in 2002 charged for energy received from the AEP mainly as a result of increased residential and Power Pool. The AEP Power Pool calculates commercial sales due to demand caused by each company's prior twelve month peak weather conditions. Changes in the demand relative to the total peak demand of components of Operating Revenues were: all member companies as a basis for sharing Increase (Decrease) revenues and costs. The result of this From Previous Year calculation is the member load ratio (MLR) (Dollars in Millions) 2002 2001 which determines each company's Amount % Amount % percentage share of AEP Power Pool Retail* $ 11 2 S(66) (8) wholesale revenues and costs. Marketing 10 5 (19) (8) unrealized MTM 2 8 33 N.M. Other 1 1 (4) (5) Results of Operations Total wholesale Electricity* 24 2 (56) (5) Income Before Extraordinary Item increased Energy Delivery* 37 7 85 18 $54 million or 33% in 2002 mainly due to Sales to AEP reductions in operating expenses, Affiliates (46) (9) (71) (12) predominantly fuel, and interest charges. Total SL15 1 VA42) (2)
- Reflects the allocation of certain Income Before Extraordinary Item increased transmission and distribution revenues
$63 million or 62% in 2001 primarily due to included in bundled retail rates to energy delivery. the effect of a court decision related to a corporate owned life insurance (COLI) During the summer months, cooling degree program recorded in 2000. In February 2001 days increased 39%. For the fall season, the U.S. District Court forthe Southern District heating degree days increased 32%. This 1-2
reflects a return to more normal weather due to a 9% decrease in net generation conditions since 2001 weather was because of decreased sales to the AEP abnormally mild. Sales to AEP Affiliates Power Pool caused by an affiliate s two decreased due to a 15% decrease in price, nuclear units returning to service. reflective of lower average fuel cost, while MWH sales rose slightly. Wholesale Electricity Purchased Power expense increased in 2002. This was the Operating Revenues decreased 2% in 2001 result of a 11% increase of MWH sales, due to decreased sales to the AEP Power partially offset by a decrease in price. In2001 Pool. This was the result of an affiliate being the increase was due to increases in MWH able to supply more power to the Power Pool purchases from third parties because of the from two nuclear units that returned to service non-availability of associated nuclear power in June and December 2000. for resale to wholesale customers and to meet internal demand. Operating Expenses AEP Affiliates Purchased Power expense Operating Expenses decreased 2% in 2002 increased in 2002 as a result of an 18% mostly due to reductions in Fuel. Operating increase of MWH purchased from affiliates Expenses in 2001 also decreased 3%. This with a slight decrease in the average price. reduction was the result of lower Fuel and The increase for 2001 was also a result of Income Taxes partially offset by amortization increased purchases through the AEP Power of transition regulatory assets. Pool. Changes in the components of Operating Maintenance expense increased in 2001 Expenses were: mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Spom Increase (Decrease) plants, and boiler inspections at the Amos and From Previous Year (dollars in millions) Cardinal Plants. 2002 2001 Amount % Amount % In 2001, the commencement of amortization Fuel SC102) (15) 5(85) (11) of transition regulatory assets in connection wholesale Electricity Purchased Power 4 6 is 30 with the transition to customer choice and AEP Affiliates market-based pricing of retail electricity supply Purchased Power 8 14 12 23 under Ohio deregulation accounted for the Other Operation 16 4 (4) (1) Maintenance (6) (4) 18 15 significant increase in Depreciation and Depreciation and Amortization 9 4 84 54 Amortization expense. Taxes Other Than Income Taxes 10 (10) (6) Income Taxes 12 12 (86) (46) The 2002 increase in Taxes Other Than Total operating Income Taxes is the result of increases in Expenses SLU4) (2) (3) state excise tax created from a change in the The Fuel expense decrease for 2002 reflects base tax calculation. The decrease in 2001 a reduction of 19% in average cost of fuel for was due to a decrease in property tax generation, offset in part by a slight increase expense reflecting a reduction in rates on in MWH generated. The decrease in fuel generation property under the Ohio costs are the result of purchasing coal at Restructuring law partially offset by a new lower prices on the open market in 2002 state excise tax. instead of affiliated company coal. Income Taxes increased in 2002 due to an Fuel expense decreased 11 % in 2001 mainly increase in both federal and state tax 1-3
expenses. Federal taxes increased due to The major reason for the decrease in Interest higher pre-tax operating income offset in part Charges in 2001 was the recognition in 2000 by changes in certain book/tax timing of deferred interest payments to the IRS differences accounted for on aflow-thru basis. related to COLI disallowances. State taxes increased predominately as a result of the State of Ohio s tax legislation Extraordinary Loss revision involving utility deregulation. In the second quarter of 2001 an Income Taxes decreased in 2001 due to an extraordinary loss of $18 million net of tax unfavorable ruling in AEP s suit against the was recorded to write-off prepaid Ohio excise government over interest deductions claimed taxes stranded by Ohio deregulation. In 2000 relating to AEP s COLI program which was the application of regulatory accounting for recorded in 2000 and a decrease in pre-tax generation under SFAS 71 was discontinued book income. which resulted in an after tax extraordinary loss of $19 million. Nonoperating Income and Nonoperating Expense 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 $1,058,250 $1,034,026 $1,090,297 Energy Delivery 589,673 552,713 467,587 Sales to AEP Affiliates 465.202 511,366 582.447 TOTAL OPERATING REVENUES 2,113.125 2.098.105 2.140.331 OPERATING EXPENSES: Fuel 584,730 686, 568 771,969 Purchased Power: wholesale Electricity 67,385 63,441 48,657 AEP Affiliates 71,154 62,585 50,741 Other operation 416,533 400,790 404,410 Maintenance 136,609 142,878 124,735 Depreciation and Amortization 248,557 239,982 155,944 Taxes other Than Income Taxes 176,247 159,778 169,527 Income Taxes 113.581 101,373 187.521 TOTAL OPERATING EXPENSES 1.814.796 1.857. 395 1.913.504 OPERATING INCOME 298,329 240,710 226,827 NONOPERATING INCOME 51,953 70,108 57,163 NONOPERATING EXPENSES 28,567 53,802 44,009 NONOPERATING INCOME TAX EXPENSE (CREDIT) 18,010 (2,380) 18,158 INTEREST CHARGES 83.682 93.603 119.210 INCOME BEFORE EXTRAORDINARY ITEM 220,023 165,793 102,613 EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (See Note 2) (18.348) (18.876) NET INCOME 220,023 147,445 83,737 PREFERRED STOCK DIVIDEND REQUIREMENTS 1.258 1.258 1,266 EARNINGS APPLICABLE TO COMMON STOCK $ 218,765 $ 146.187 Statements of Comorehensive Income Year Ended December 31. (in thousands) 2002 2001 2000 NET INCOME $2220, 023 $147,445 $;83,737 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (542) (196) Minimum Pension Liability (72.148) COMPREHENSIVE INCOME 3 147,333 $147,249 I The common stock of oPco is wholly owned by AEP. See Notes to Financial statements beginning on page L-1. 1-5
OHIO POWER COMPANY Statement of Retained Earninqs Year Ended December 31. 2002 2001 2000 (in thousands) Retained Earnings January 1 $401,297 $398,086 $587,424 Net Income 220,023 147.445 83,737 621,320 545.531 671. 161 Deductions: cash Dividends Declared: Common stock 97,746 142,976 271,813 Cumulative Preferred Stock: 4.08% series 58 58 59 4.20% series 96 96 96 4.40% Series 139 139 139 4-1/2% Series 439 439 442 5.90% series 428 428 428 6.02% Series 66 66 66 6.35% series 32 32 32 Total Dividends 99,004 144,234 273,075 Retained Earnings December 31 MZJI-6 $AO1,291 $3-9&JO see Notes to Financia7 statements beginning on page L-1. 1-6
OHIO POWER COMPANY Balance Sheets December 31. 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,116,825 $3,007,866 Transmission 905,829 891,283 Distribution 1,114,600 1,081,122 General 260,153 245,232 Construction work in Progress 288.419 165,073 Total Electric Utility Plant 5,685,826 5,390,576 Accumulated Depreciation and Amortization 2. 566.828 2.452.571 NET ELECTRIC UTILITY PLANT 3.118.998 2.938.005 OTHER PROPERTY AND INVESTMENTS 61,686 62.303 LONG-TERM ENERGY TRADING CONTRACTS 103.230 99.706 CURRENT ASSETS: cash and Cash Equivalents 5,285 8,848 Accounts Receivable: Customers 95,100 84,694 Affiliated Companies 124,244 148,563 Miscellaneous 19,281 20,409 Allowance for uncollectible Accounts (909) (1,379) Fuel 87,409 84,724 Materials and Supplies 85,379 88,768 Energy Trading Contracts 92,108 114,280 Prepayments and other 12.083 20,865 TOTAL CURRENT ASSETS 519.980 569.772 REGULATORY ASSETS 568.641 644.625 DEFERRED CHARGES 84.497 79.662 TOTAL ASSETS SAA45 t932 4A07 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 $ 321,201 $ 321,201 Paid-in capital 462,483 462,483 Accumulated other Comprehensive Income (Loss) (72,886) (196) Retained Earnings 522. 316 401,297 Total Common Shareholder s Equity 1,233,114 1,184,785 Cumulative Preferred Stock: Not subject to Mandatory Redemption 16,648 16,648 subject to Mandatory Redemption 8,850 8,850 Long-term Debt 917.649 1.203,841 TOTAL CAPITALIZATION 2. 176.261 2.414.124 OTHER NONCURRENT LIABILITIES 227,689 130, 386 CURRENT LIABILITIES: Long-term Debt Due within One Year - General 89,665 Long-term Debt Due within one Year Affiliated Companies 60,000 short-term Debt Affiliated Companies 275,000 Advances From Affiliates 129,979 300,213 Accounts Payable General 170,563 131,057 Accounts Payable Affiliated Companies 145,718 176, 520 Customer Deposits 12,969 5,452 Taxes Accrued 111,778 126,770 Interest Accrued 18,809 17,679 obligations under Capital Leases 14,360 16,405 Energy Trading Contracts 61,839 98,081 other 80.608 90.431 Total CURRENT LIABILITIES 1,171,288 962.608 DEFERRED INCOME TAXES 794.387 797.889 DEFERRED INVESTMENT TAX CREDITS 18.748 21.925 LONG-TERM ENERGY TRADING CONTRACTS 39,702 50,459 REGULATORY LIABILITIES AND DEFERRED CREDITS 28.957 16.682 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES 54,45,032 $4,3-9A4-0173 See Notes to Financia7 Statements beginning on page L-1. 1-8
OHIO POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $ 220,023 $ 147,445 S 83,737 Adjustments for Noncash Items: Depreciation, Depletion and Amortization 248,557 252,123 200,350 Deferred Income Taxes 46,010 215,833 (65,956) Deferred Investment Tax credits (3,177) (3,289) (3,399) Deferred Fuel Costs (net) (56,869) Extraordinary Loss 18,348 18,876 Mark to Market of Energy Trading Contracts (28,693) (59,833) (5,614) change in Certain Current Assets and Liabilities: Accounts Receivable (net) 14,571 51,640 51,430 Fuel, Materials and Supplies 704 4,852 46,645 Accrued Utility Revenues 3,081 264 45,311 Accounts Payable 8,704 9,887 56,069 Customer Deposits 7,517 (34,284) 31,540 Taxes Accrued (14,992) (96,331) 60,919 Disputed Tax and Interest Related to COLI 110,494 Employee Benefit and other Noncurrent Liabilities 110,298 (392,026) 145,573 Impairment Loss 1,757 change in other Assets (2,233) 79,831 (439,448) change in other Liabilities (133.154) (107.704) 359.640 Net Cash Flows From Operating Activities 478.973 86.756 639,298 INVESTING ACTIVITIES: Construction Expenditures (354,797) (344,571) (254,016) Proceeds From Sales of Property and other 6,499 16,778 6,354 Investment in coal Companies (32,115) Net Cash Flows used For Investing Activities (348,298) (359.908) (247,662) FINANCING ACTIVITIES: Issuance of Long-term Debt 300,000 74,748 change in Advances From Affiliates (net) (170,234) 392,699 (92,486) Retirement of cumulative Preferred stock (182) Retirement of Long-term Debt (140,000) (297,858) (30,663) change in short-term Debt (net) 275,000 (194,918) Dividends Paid on Common stock (97,746) (142,976) (271,813) Dividends Paid on cumulative Preferred stock (1.258) (1,258) (1,262) Net cash Flows From (Used For) Financing Activities (134.238) 250,607 (516, 576) Net Decrease in cash and cash Equivalents (3,563) (22,545) (124,940) cash and cash Equivalents January 1 8.848 31. 393 156.333 cash and cash Equivalents December 31 $ S5, 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) COMMON SHAREHOLDER S EQUITY $1.233.114 S1.184.785 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 1,460 1,460 4.20% 103.20 - - 276 22,824 2,282 2,282 4.40% 104 - - 432 31,512 3,151 3,151 4-1/2% 110 - - 2.181 97.546 9.755 9.755
- 16. 648 16.648 subject to Mandatory Redemption-S100 Par (b):
5.90% (c) $- - - 72,500 7,250 7,250 6.02% (d) - - - 11,000 1, 100 1,100 6.35% (d) - - - 5,000 500 500 8.850 8.850 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 sufficient to enable the payment of interest on follows: and the principal of (at stated maturities and December 31. 2002 2001 upon mandatory redemptions) related (in thousands) pollution control revenue bonds issued to % Rate Due 6.75 2003 April 1 S 29,850 S 29,850 finance the construction of pollution control 6.55 2003 October 1 27.315 27,315 facilities at certain plants. 6.00 2003 November 1 12,500 12,500 6.15 2003 December 1 20,000 20,000 (a) 2022 - February 10 - 5,000 Senior unsecured notes outstanding were as 7.75 2023 April 1 5,000 5,000 7.375 2023 October 1 20,250 20,250 follows: 7.10 2023 - November 1 12,000 12,000 December 31. 7.30 2024 April 1 10,000 10,000 2002 2001 Unamortized Discount (282) (371) (in thousands) Total 1135 633 5141, 4A % Rate Due 6.75 2004 July 1 $100,000 $100,000 (a) Redeemed on May 10, 2002. 7.00 2004 July 1 75,000 75,000 6.73 2004 November 1 48,000 48,000 6.24 2008 December 4 37,225 37,225 First mortgage bonds are secured by a first 7-3/8 2038 June 30 140,000 140,000 unamortized Discount (2.884) (39263) mortgage lien on electric utility plant. Certain Total S37,4 supplemental indentures to the first mortgage lien contain maintenance and replacement Notes payable to parent company were as provisions requiring the deposit of cash or follows: December 31. bonds with the trustee, or in lieu thereof, 2002 2001 (in thousainds) certification of unfunded property additions. % Rate Due 4.336% 2003 May 15 S 60,000 S 60,000 6.501% 2006 May 15 240.000 240.000 Installment purchase contracts have been Total Sa_,0 entered into in connection with the issuance of pollution control revenue bonds by Junior debentures outstanding were as governmental authorities as follows: follows: December 31. December 31. 2002 2001 2002 2001 (in thousands) (in thousands) % Rate Due % Rate Due (a) 2025 September 30 S - S 85,000 (a) 2027 March 31 - 50,000 Mason County, West unamortized Discount - (2.900) Virginia: Total 1 - si 5.45% 2016 December I S 50,000 S 50,000 (a) Redeemed on July 24, 2002 Marshall county, West Virginia: 5.45% 2014 July 1 50,000 50,000 5.90% 2022 April 1 35,000 35,000 At December 31, 2002 future annual long-6.85% 2022 Ohio Air Quality June 1 50,000 50,000 term debt payments are as follows: Development Amount 5.15% 2026 May 1 50,000 50,000 (in thousands) unamortized Discount (1.660) (1.765) 2003 S 149,665 Total 12I33,34 2004 223,000 2005 2006 240,000 Under the terms of the installment purchase 2007 contracts, OPCo is required to pay amounts Later Years 459.475 Total Principal Amount 1,072,140 unamortized Discount 4 826 Total 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. Combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 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 Impairments 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 Supplementary Information Note 20 Leases Note 22 Lines of credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Related Party Transactions 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 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $ 793,647 $957,000 $956,398 $749,390 $780,159 operating Expenses 708.926 860.012 859.729 650.677 665.085 operating Income 84,721 96,988 96,669 98,713 115,074 Nonoperating Items, Net (3,239) 20 8,974 946 (91) Interest charges 40.422 39.249 38,980 38.151 38.074 Net Income 41,060 57,759 66,663 61,508 76,909 Preferred stock Dividend Requirements 213 213 212 212 213 Gain on Reacquired Preferred stock 1 Earnings Applicable to Common stock $ 40.848 LiZJ_.~ 1_0,A5I1 S-512% 96 $76-, December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $2,759,504 $2,695,099 $2,604,670 $2,459,705 $2,391,722 Accumulated Depreciation and Amortization 1.239,855 1.184.443 1.150.253 1,114.255 1.082.081 Net Electric Utility Plant $i,519,649 $1,510,656 $1.,454,417 $1 , 3A5,45Q Total Assets $1,76,69 24 $IAZ10 Common stock and Paid-in capital $ 337,246 $ 337,246 $ 337,246 $ 337,246 S 337,246 Accumulated other Comprehensive Income (Loss) (54,473) Retained Earnings 116.474 142.994 137,688 139.237 142. 941 Total Common shareholder's Equity S 399,247 $ 480s2A0 $ 474,934 S 476,483 cumulative Preferred Stock: Not subject to Mandatory Redemption $ 5. 27 Preferred securities of subsidiary Trust $LJ575000 S 75QQ0 Long-term Debt (a) $ 545,437 $ 451,129 $_384,064 Total capitalization and Liabilities ILi7Q $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) Changes in Operating Expenses is a public utility engaged in the generation, purchase, sale, transmission and distribution Increase (Decrease) From Previous Year of electric power to approximately 505,000 (dollars in millions) Amount % retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at Fuel S(215.3) (47) Purchased Power: wholesale to other utilities, municipalities and wholesale Electricity 23.3 96 rural electric cooperatives. AEP Affiliates 45.7 104 other operation (4.1) (3) Maintenance 1.9 4 Wholesale power marketing activities are Depreciation and Amortization 5.6 7 conducted on PSO s behalf byAEPSC. PSO, Taxes other Than along with the other AEP electric operating Income Taxes 2.1 7 Income Taxes (10.3) (30) subsidiaries, shares in AEP s electric power Total S(514) (18) transactions with other utility systems and N.M. = Not Meaningful power marketers. The decrease in Fuel expense in 2002 was Results of Operations primarily due to lower market prices for natural gas and fuel oil, and deferral of In 2002, Net Income decreased by $17 million underrecovered fuel costs due to the ICR or 29% primarily resulting from reduced adjustments through the fuel clause recovery wholesale margins and increased mechanism (see Note 6) and to the depreciation expense. amortization of previously overrecovered fuel costs. Changes in Operating Revenues The increase in Electricity Marketing Operating revenues decreased in 2002 as a Purchased Power expense in 2002 resulted result of reduced wholesale margins, a mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices. decline in fuel recovery revenue and decreases due to the interchange cost The increase in the AEP Affiliates Purchased reconstruction (ICR) adjustments (see Note Power expense in 2002 resulted mainly from 6). the ICR adjustments (see Note 6). Increase (Decrease) From Previous Year (dollars in millions) Other Operation expense decreased in 2002 Amount % primarily due to lower transmission expenses wholesale Electricity* S(149.7) (23) and decreased factoring expenses due to Energy Delivery* 13.6 5 reduced revenues. sales to AEP Affiliates t27.3) (74) Total operating Revenues S(163) (17) Maintenance expense increased, in 2002
- Reflects the allocation of certain transmission and distribution revenues largely as a result of increased expenses to included in bundled retail rates to energy repair damage to overhead lines caused by a delivery.
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 ZO21 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $508,661 $658,352 $696,626 Energy Delivery 275,547 261,877 245,124 Sales to AEP Affiliates 9,439 36.771 14, 64 8 TOTAL OPERATING REVENUES 793,647 957.000 956. 398 OPERATING EXPENSES: Fuel 246,199 461,470 402,933 Purchased Power: wholesale Electricity 47,507 24,187 88,088 AEP Affiliates 89,454 43,758 60,788 other operation 133,538 137,678 121,697 Maintenance 48,060 46,188 45,858 Depreciation and Amortization 85,896 80,245 76,418 Taxes other Than Income Taxes 34,077 31,973 28,688 Income Taxes 24.195 34,513 35,259 TOTAL OPERATING EXPENSES 708.926 860.012 859.729 OPERATING INCOME 84,721 96,988 96,669 NONOPERATING INCOME 1,920 2,112 8,807 NONOPERATING EXPENSES 6,971 1,740 1,139 NONOPERATING INCOME TAX EXPENSE (CREDIT) (1,812) 352 (1,306) INTEREST CHARGES 40.422 39.249 38.980 NET INCOME 41,060 57,759 66,663 GAIN ON REACQUIRED PREFERRED STOCK 1 LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 213 213 212 EARNINGS APPLICABLE TO COMMON STOCK $ 40,848 ,$L5 $ 66AS5 Consolidated Statements of Comprehensive Income Year Ended December 31. 2002 2001 2000 (in thousands) NET INCOME $ 41,060 $57,759 $66,663 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (42) Minimum Pension Liability (54.431) COMPREHENSIVE INCOME (LOSS) $ (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 2000 (in thousands) BEGINNING OF PERIOD $142,994 $137,688 $139,237 NET INCOME 41,060 57,759 66,663 DEDUCTIONS: capital Stock Gains (1) Cash Dividends Declared: Common stock 67,368 52,240 68,000 Preferred stock 213 213 212 BALANCE AT END OF PERIOD $116,474 $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 $1,040,520 $1,034,711 Transmission 432,846 427,110 Distribution 990,947 972,806 General 206,747 203,572 Construction work in Progress 88.444 56.900 Total Electric utility Plant 2,759,504 2,695,099 Accumulated Depreciation and Amortization 1.239.855 1,184.443 NET ELECTRIC UTILITY PLANT 1.519.649 1,510,656 OTHER PROPERTY AND INVESTMENTS 41.020 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4.481 21. 354 CURRENT ASSETS: Cash and Cash Equivalents 16,774 5,795 Accounts Receivable: Customers 31,687 31,144 Affiliated companies 14,139 10,905 Allowance for uncollectible Accounts (84) (44) Fuel Inventory 19,973 21,559 Materials and supplies 37,375 36,785 under-recovered Fuel Costs 76,470 756 Energy Trading and Derivative Contracts 3,841 26,259 Prepayments and other 2.735 2.368 TOTAL CURRENT ASSETS 202.910 135. 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 December 31, 2002 2001 (in thousands) CAPTTALIZATION AND LIARILTTIFS CAPITALIZATION: Common Stock $15 Par value: Authorized shares: 11,000,000 Issued Shares: 10,482,000 outstanding Shares: 9,013,000 S 157,230 $ 157,230 Paid-in capital 180,016 180,016 Accumulated Other Comprehensive Income (Loss) (54,473) Retained Earnings 116,474 142.994 Total Common shareholder s Equity 399. 247 480.240 Cumulative Preferred stock Not subject to Mandatory Redemption 5,267 5,267 Pso-obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 445.437 345.129 TOTAL CAPITALIZATION 924.951 905.636 OTHER NONCURRENT LIABILITIES 54.761 7,263 CURRENT LIABILITIES: Long-term Debt Due within One Year 100,000 106,000 Advances from Affiliates 86,105 123,087 Accounts Payable General 61,169 72,759 Accounts Payable Affiliated Companies 78,076 40,857 Customer Deposits 21,789 21,041 Over-Recovered Fuel Costs 9,476 Taxes Accrued 6,854 18,150 Interest Accrued 6,979 7,298 Energy Trading and Derivative Contracts 3,260 31,718 other 24. 957 12,216 TOTAL CURRENT LIABILITIES 389.189 442.602 DEFERRED INCOME TAXES 341.396 296.877 DEFERRED INVESTMENT TAX CREDITS 32.201 33,992 REGULATORY LIABILITIES AND DEFERRED CREDITS 32.611 49.080 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,581 13.461 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $1,776,690 $1.748, 911. See Notes to Financia7 statements beginning on page L-1. 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 $ 41,060 $ 57,759 S 66,663 Adjustments to Reconcile Net Income to Net Cash from operating Activities: Depreciation and Amortization 85,896 80,245 76,418 Deferred Income Taxes 75,659 (17,751) 25,453 Deferred Investment Tax Credits (1,791) (1,791) (1,791) changes in Certain Assets and Liabilities: Accounts Receivable (net) (3,737) 21,405 (28,826) Fuel, Materials and supplies 996 (589) 677 other Property and Investments (419) (2,809) 7,994 Accounts Payable 25,629 (55,319) 89,330 Taxes Accrued (11,296) 16,491 (16,821) Fuel Recovery (85,190) 51,987 (36,798) Transmission Coordination Agreement settlement (15,063) changes in Other Assets 2,215 (9,120) 4,482 changes in Other Liabilities (6,928) 9.351 65.6193 Net Cash From Operating Activities 122.094 149,859 165.615 INVESTING ACTIVITIES: Construction Expenditures (124,520) (176,851) Proceeds from Sale of Property 963 other Items (359) Net cash used For Investing Activities (88.402) (124,879) (176.851) FINANCING ACTIVITIES: Issuance of Long-term Debt 187,850 105,625 Retirement of Long-term Debt (106,000) (20,000) (20,000) Change in Advances From Affiliates (net) (36,982) 41,967 1,951 Dividends Paid on Common Stock (67,368) (52,240) (68,000) Dividends Paid on cumulative Preferred stock (213) (213) (212) Net cash From (used For) Financing Activities (22,713) (30, 486) Net Increase (Decrease) in cash and cash Equivalents 10,979 (5,506) 8,128 cash and cash Equivalents January 1 11.301 3 .173 cash and cash Equivalents December 31 $1 5.795 6977 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) COMMON SHAREHOLDER S EQUITY $ 399.247 $480.240 PREFERRED STOCK: Cumulative $100 par value authorized shares 700,000, redeemable at the option of PSO upon 30 days notice. Call Price Shares December 31, Number of shares Redeemed outstanding Series 2002 Year Ended December 31, December 31. 2002 2002 2001 2000 Not subject to Mandatory Redemption: 4.00% $105.75 6 - 25 44,600 4,460 4,460 4.24% 103.19 - - - 8,069 807 807 5.267 5.267 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 75.000 75.000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 298,079 297,772 Installment Purchase Contracts 47,358 47,357 senior unsecured Notes 200,000 106,000 Less Portion Due Within one Year (100.000) (106. 000) Long-term Debt Excluding Portion Due within one Year 445.437 345.129 TOTAL CAPITALIZATION see Notes to Financial Statements beginning on page L-1. J-9
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Lona-term Debt First mortgage bonds outstanding were as Under the terms of the installment purchase follows: contracts, PSO is required to pay amounts December 31. sufficient to enable the payment of interest on 2002 2001 and the principal of (at stated maturities and (in thousands) % Rate Due upon mandatory redemptions) related 6.25 2003 April 1 S 35,000 S 35.000 pollution control revenue bonds issued to 7.25 2003 July 1 65,000 65,000 7.38 2004 December 1 50,000 50,000 finance the construction of pollution control 6.50 2005 7.38 2023 June 1 April 1 50,000 100,000 50,000 100, 000 facilities at certain plants. unamortized Discount (1.921) (2 228) S29Bs29 Senior unsecured notes outstanding were as First mortgage bonds are secured by a first follows: mortgage lien on electric utility plant. The December 31. indenture, as supplemented, relating to the 2002 2001 (in thousands) first mortgage bonds contains maintenance % Rate Due (a)i 2002 November 21 S - S106,000 and replacement provisions requiring the (b) 2032 December 31 200 000 - deposit of cash or bonds with the trustee, or in TOTAL 520 00M 16 0 lieu thereof, certification of unfunded property (a) A floating interest rate is determined additions. monthly. was $2.775%. The rate on December 31, 2001 (b) A fixed interest rate of 6.00% was the rate on December 31, 2002. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by At December 31, 2002, future annual long-governmental authorities as follows: term debt payments are as follows: December 31. Amount 2002 2001 (in thousands) (in thousands) Rat Due 2003 $100,000 Oklahoma Environmental 2004 50,000 Finance Authority (OEFA): 2005 50,000 5.90 2007 - December 1 S 1,000 S 1,000 2006 2007 1,000 Oklahoma Development Later Years 346. 360 Finance Authority (ODFA): Total Principal Amount 547, 360 4.875 2014 - June 1 33,700 33,700 unamortized Discount (1.923) Red River Authority Total 545 437 of Texas: 6.00 2020 June 1 Unamortized Discount 12,660 12,660 See Note 25 for discussion of the Trust (2) (3) Total i ,Al 3-58 547 357 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 Year Enided December 31, -- - - 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $1,084,720 $1,101,326 $1,118,274 $ 971,527 $ 952,952 operating Expenses 942.251 955,119 989.996 824,465 802,274 operating Income 142,469 146,207 128,278 147,062 150,678 Nonoperating Items, Net (309) 741 3,851 (1,965) 2,451 Interest Charges 59,168 57, 581 59,457 _ 58,892 5,9135 Income Before Extraordinary Item 82,992 89,367 72,672 86,205 97,994 Extraordinary Loss (3,011) Net Income 82,992 89,367 72,672 83,194 97,994 Preferred stock Dividend Requirements 229 229 229 229 705 LOSS on Reacquired Preferred stock Earnings Applicable to Common stock $ 8J39& U$ 72,443 _$--- a33 December 31, 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,596,174 $3,460,764 $3,319,024 $3,231,431 $3,157,911 Accumulated Depreciation and Amortization 1. 697. 338 1,550,618 1,457,005 1.384.242 1.317.057 Net Electric Utility Plant -$i Q0,146 $1&862019 -£2 IQ-85A'25 Total Assets $2 2SL67I5 16762:
,2
$L380,616 $ 380,663 Common stock and Paid-in capital $ 380,663 $ 380,663 $ 380,663 $ 380,663 $ 380,663 Accumulated other Comprehensive Income (Loss) (53,683)
Retained Earnings 334,789 308,915 293,989 283, 546 296, 581 Total Common shareholder's Equity S$_&6W5i8 $-6!A.-5i2 S-664,ZO0 $_677L244 Preferred stock $ 4=,=z2 .11 1 LQ1 $ 4,70-1~ 2Q Trust Preferred securities $__11O0,Q $ 110,000 A114QQ00 £_lUXlQQQ Long-term Debt (a) _$__M -t645 S& 6A45,963 A15& Total capitalization and Liabilities £$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 Operating Revenues decreased 2% for 2002 (SWEPCo) is a public utility engaged in the primarily due to decreased fuel revenues generation, purchase, sale, transmission and offset in part by the addition of the Dolet Hills distribution of electric power to approximately mining operation ($12.6 million) and the 437,000 retail customers in northeastern positive impact of the interchange cost Texas, northwestern Louisiana and western reconstruction (ICR) adjustments (see Note Arkansas. SWEPCo also sells electric power 6). at wholesale to other utilities, municipalities and rural electric cooperatives. In 2001, Operating Revenues decreased $17 million or 2% resulting from unfavorable Wholesale power marketing activities are wholesale marketing and trading conditions. conducted on SWEPCo s behalf by AEPSC. SWEPCo, along with the other AEP electric Changes in Operating Expenses operating subsidiaries, shares in AEP s Increase (Decrease) electric power transactions with other utility From Previous Year systems and power marketers. (dollars in millions) 2002 2001 Amount % Amount X Results of Operations Fuel S(69) (15) S(41) (8) Purchased Power: In 2002, Net Income decreased $6.4 million or wholesale 7% primarily resulting from reduced margins. Electricity 26 143 (40) (69) AEP In 2001, Net Income increased $16.7 million Affiliates 26 165 2 19 or 23% resulting primarily from the favorable other operation 18 10 12 7 impact of our sharing in AEP s power Maintenance (8) (10) - (1) marketing activities for a full year. Depreciation and Amortization 3 3 15 14 Taxes other Changes in Operating Revenues Than Income Taxes (1) (1) 2 4 Income Taxes (20) 16 60 Increase (Decrease) Total (8) (1) £LI) (4) From Previous Year (dollars in millions 2002 2001 Fuel expense decreased in 2002 due to a Amount % Amount % reduction in MWH generated and a decrease wholesale in the cost of fuel, primarily natural gas. Electricity* $(25) (4) S(21) (3) Energy Delivery* 15 5 (12) (3) Sales to AEP Fuel expense decreased in 2001 from lower Affiliates .7) (9) 16 26 natural gas prices and a mild summer Total operating resulting in a reduction in generation. Revenues £-1Z) (2) ILU) (2)
- Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
K-2
L. In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In2001, 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 $ 664,185 $ 689,085 $ 710,200 Energy Delivery 348,236 333,004 344,950 Sales to AEP Affiliates 72,299 79,237 63,124 TOTAL OPERATING REVENUES 1.084,720 1.101.326 1.118.274 OPERATING EXPENSES: Fuel 388,334 457,613 498,805 Purchased Power: wholesale Electricity 44,119 18,164 58,518 AEP Affiliates 42,022 15,858 13,338 other operation 189,024 171,314 159,459 Maintenance 66,855 74,677 75,123 Depreciation and Amortization 122,969 119,543 104,679 Taxes other Than Income Taxes 55,232 55,834 53,830 Income Taxes 33,696 42,116 26,244 TOTAL OPERATING EXPENSES 942.251 955.119 989, 996 OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 4,512 5,487 NONOPERATING EXPENSES 1,797 3,229 3,112 NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,772 542 (1,476) INTEREST CHARGES 59.168 57, 581 59.457 NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229 EARNINGS APPLICABLE TO COMMON STOCK S 82.e763 S 89,138 S 72.443 Consolidated Statements of Comprehensive Income Year Ended December 31. 2002 2001 2000 (in thousands)
--- --- $72,672 NET INCOME $82,992 $89,36 7 OTHER COMPREHENSIVE INCOME (LOSS):
cash Flow Power Hedges (48) - Minimum Pension Liability (53.635) - COMPREHENSIVE INCOME "24.309 S___36 $72 f92 The common stock of SWEPco is owned by a who77y owned subsidiary of AEP. See Notes to Financial statements beginning on page L-1. 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 $308,915 $293,989 $283,546 NET INCOME 82,992 89,367 72,672 DEDUCTIONS: cash Dividends Declared: Common stock 56,889 74,212 62,000 Preferred stock 229 229 229 BALANCE AT END OF PERIOD $ 3C&4915 $s91I9&9 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 $1,503,722 $1,429,356 Transmission 575,003 538,749 Distribution 1,063,564 1,042,523 General 378,130 376,016 Construction work in Progress 75,755 74.120 Total Electric utility Plant 3,596,174 3,460,764 Accumulated Depreciation and Amortization 1.697. 338 1.550.618 NET ELECTRIC UTILITY PLANT 1.898.836 1.910,146 OTHER PROPERTY AND INVESTMENTS 5,978 43.000 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 5,119 24,508 CURRENT ASSETS: Cash and cash Equivalents 2,069 5,415 Accounts Receivable: Customers 62,359 43,133 Affiliated Companies 19,253 12,069 Allowance for uncollectible Accounts (2,128) (89) Fuel Inventory 61,741 52,212 Materials and supplies 33,539 32,527 Under-recovered Fuel Costs 2,865 8,839 Energy Trading and Derivative Contracts 4,388 30,139 Prepayments and other 17,851 18,716 TOTAL CURRENT ASSETS 201.937 202.961 REGULATORY ASSETS 49,233 52. 308 DEFERRED CHARGES 47. 572 67, 753 TOTAL ASSETS $2,20,65 $2,300,676 see Notes to Financia7 statements beginning on page L-1. K-6
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES December 31. 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stock $18 Par value: Authorized 7,600,000 Shares Outstanding 7,536,640 shares $ 135,660 $ 135,660 Paid-in capital 245,003 245,003 Accumulated other Comprehensive Income (Loss) (53,683) Retained Earnings 334,789 308.915 Total Common shareholder s Equity 661,769 689,578 Preferred stock 4,701 4,701 SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo 110,000 110,000 Long-term Debt 637.853 494,688 TOTAL CAPITALIZATION 1.414.323 1. 298.967 OTHER NONCURRENT LIABILITIES 78.494 40,109 CURRENT LIABILITIES: Long-term Debt Due within One Year 55,595 150, 595 Advances from Affiliates, net 23,239 117,367 Accounts Payable General 62,139 71,810 Accounts Payable Affiliated Comp;ani es 58,773 37,469 Customer Deposits 20,110 19,880 Taxes Accrued 19,081 36,522 Interest Accrued 17,051 13,027 Energy Trading and Derivative Cont racts 3,724 36,297 over-recovered Fuel 17,226 5,487 other 34, 565 26,074 TOTAL CURRENT LIABILITIES 311.503 514.,528 DEFERRED INCOME TAXES 341.064 369.78 DEFERRED INVESTMENT TAX CREDITS 44,190 48.714 REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 13.,127 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1.806 15,45S0 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $2,208,675 2LINJ7U See Notes to Financia7 statements beginning on page L-1. 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 $ 82,992 $ 89,367 S 72,672 Adjustments to Reconcile Net Income to Net cash Flows From Operating Activities: Depreciation and Amortization 122,969 119,543 104,679 Deferred Income Taxes (3,134) (31,396) 14,653 Deferred Investment Tax credits (4,524) (4,453) (4,482) Mark-to-Market Energy Trading and Derivative Contracts (1,151) (10,695) 7,795 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (24,371) (11,447) (1,254) Fuel, Materials and supplies (10,541) (19,578) 22,103 Accounts Payable 11,633 (34,489) 43,962 Taxes Accrued (17,441) 25,298 (13,150) Transmission coordination Agreement Settlement (24,406) Fuel Recovery 17,713 34,423 (38,357) change in other Assets 24,257 1,323 54,414 change in other Liabilities 12.16 11, 714 (37.001) Net cash Flows From Operating Activities 210.563 169.610 201.628 INVESTING ACTIVITIES: Construction Expenditures (111,775) (111,725) (120,671) Purchase of Dolet Hills Mining operations (85,716) other 1.134 (411) 446 Net cash Flows used For - Investing Activities (110.641) (197.852) (120.225) FINANCING ACTIVITIES: Issuance of Long-term Debt 198,573 149,360 Redemption of Preferred stock (1) Retirement of Long-term Debt (150,595) (595) (45,595) Change in Advances From Affiliates (net) (94,128) 106,786 (124,074) Dividends Paid on Common Stock (56,889) (74,212) (62,000) Dividends Paid on Cumulative Preferred Stock (229) (229) (229) Net cash Flows From (used For) Financing Activities (103,268) 31.750 (82.5 39) Net Increase (Decrease) in cash and cash Equivalents (3,346) 3,508 (1,136) Cash and Cash Equivalents January 1 5.415 1.907 3.043 cash and cash Equivalents December 31 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) COMMON SHAREHOLDER S EQUITY S 661.769 $ 689.578 PREFERRED STOCK: $100 par value authorized shares 1,860,000 call Price Shares December 31, Number of shares Redeemed Outstanding series 2002 Year Ended December 31E December 31. 2002 2002 2001 2000 Not subject to Mandatory Redemption: 4.28% $103.90 - - - 7,386 740 740 4.65% $102.75 - - - 1,907 190 190 5.00% $109.00 - - 12 37,715 3.771 3. 771 4.701 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 110.000 110.000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 315,420 315,449 Installment Purchase Contracts 179,183 179,834S Senior Unsecured Notes 198,845 150,000 Less Portion Due within one Year (55.595) (150. 595) Long-term Debt Excluding Portion Due within one Year 637. 853 494.688 TOTAL CAPITALIZATION 11_41Mv23 See Notes to Financial statements beginning on page L-1. K-9
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as Under the terms of the installment purchase follows: contracts, SWEPCo is required to pay December 31, 2002 2001 amounts sufficient to enable the payment of (in thousands) interest on and the principal of (at stated % Rate Due 6-5/8 2003 February 1 S 55,000 S 55,000 maturities and upon mandatory redemptions) 7-3/4 2004 June 1 40,000 40,000 related pollution control revenue bonds issued 6.20 2006 November 1 5,505 5,650 6.20 2006 November 1 1,000 1,000 to finance the construction of pollution control 7.00 2007 7-1/4 2023 Se tember I Juqy 1 90,000 45,000 90,000 45,000 facilities at certain plants. 6-7/8 2025 October 1 80 000 80,000 unamortized Discount (1.085) (1.201) Senior unsecured notes outstanding were as S315-420 follows: First mortgage bonds are secured by a first December 31, mortgage lien on electric utility plant. The 2002 2001 indenture, as supplemented, relating to the % Rate Due Otiw thousandcs-) first mortgage bonds contains maintenance 4.50 2005 July 1 S200,000 S - (a) 2002 March 1 - 150,000 and replacement provisions requiring the Unamortized Discount _. 198;85 5) 0OO deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property (a)A floating interest rate is determined additions. monthly. The rate on December 31, 2001 was 2.311%. Installment purchase contracts have been At December 31, 2002 future annual long-entered into in connection with the issuance term debt payments are as follows: of pollution control revenue bonds by Amount governmental authorities as follows: (in thousands) 2003 S 55,595 December 31, 2004 52,885 2002 2001 2005 200,595 (in thousands) 2006 6,520 % Rate Due 2007 90,450 DeSoto County: Later Years 287.695 Total Principal Amount 693,740 7.60 2019 January 1 S 53,500 $ 53,500 unamortized Discount (292) Total S69344 Sabine: 6.10 2018 April 1 81,700 81,700 See Note 25 for discussion of Trust Preferred Titus County: Securities issued by awholly-owned statutory 6.90 2004 - November 1 12,290 12,290 business trust of SWEPCo. 6.00 2008 - January 1 12,620 13,070 8.20 2011 August 1 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. combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Goodwill and other Intangible Assets Note 3 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 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 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 AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 19. Basic and Diluted Earnings Per Share AEP
- 20. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo
- 21. Power and Distribution Projects AEP
- 22. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 23. Lines of Credit and Sale of Receivables AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 24. Unaudited Quarterly Financial Information AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 25. Trust Preferred Securities AEP, PSO, SWEPCo, TCC
- 26. Minority Interest in Finance Subsidiary AEP
- 27. Equity Units AEP
- 28. Jointly Owned Electric Utility Plant
- CSPCo, PSO, SWEPCo, TCC, TNC
- 29. Related Party Transactions AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 30. Subsequent Events (Unaudited) AEP L-2
- 1. Significant Accounting Policies: operations and transmission rates and the state commissions regulate retail rates. The prices Business Operations AEP s (the Company s) charged by foreign subsidiaries located in China, principal business conducted by its eleven Mexico and Brazil are regulated bythe authorities domestic electric utility operating companies is the of that country and are generally subject to price generation, transmission and distribution of controls.
electric power. Nine of AEP s eleven domestic electric utility operating companies, APCo, Principles of Consolidation AEP s consolidated CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, financial statements include AEP Co., Inc. and its TCC, TNC, are SEC registrants. AEGCo is a wholly-owned and majority-owned subsidiaries domestic generating company wholly-owned by consolidated with their wholly-owned or AEP that is an SEC registrant. These companies substantially controlled subsidiaries. The are subject to regulation by the FERC under the consolidated financial statements for APCo, Federal Power Act and follow the Uniform System CSPCo, I&M, PSO, SWEPCo and TCC include of Accounts prescribed by FERC. They are the registrant and its wholly-owned subsidiaries. subject to further regulation with regard to rates Significant intercompany items are eliminated in and other matters by state regulatory consolidation. Equity investments not commissions. substantially controlled that are 50% or less owned are accounted for using the equity method AEP also engages in wholesale marketing and with their equity earnings included in Other trading of electricity, natural gas and to a lesser Income forAEP and nonoperating income for the extent, other commodities in the United States registrant subsidiaries. and Europe. In addition,theCompanysdomestic operations include non-regulated independent Basis ofAccounting - As the owner of cost-based power and cogeneration facilities, coal mining and rate-regulated electric public utility companies, intra-state midstream natural gas operations in AEP Co., Inc.'s consolidated financial statements Louisiana and Texas. reflect the actions of regulators that result in the recognition of revenues and expenses in different International operations include supply of time periods than enterprises that are not rate-electricity and other non-regulated power regulated. In accordance with SFAS 71, generation projects in the United Kingdom, and to "Accounting for the Effects of Certain Types of a lesser extent in Mexico, Australia, China and the Regulation, regulatory assets (deferred Pacific Rim region. These operations are either expenses) and regulatory liabilities (future wholly-owned or partially-owned by various AEP revenue reductions or refunds) are recorded to subsidiaries. We also maintained operations in reflect the economic effects of regulation by Brazil through the fourth quarter of 2002. See matching expenses with their recovery through Note 13 for discussion of impaired investments regulated revenues. Application of SFAS 71 for and assets held for sale. the generation portion of the business was discontinued as follows: in Ohio by OPCo and The Company also operates domestic barging CSPCo in September 2000, in Virginia and West operations, provides various energy related Virginia byAPCo in June 2000, in Texas byTCC, services and furnishes communications related TNC, and SWEPCo in September 1999 and in services domestically. See Note 13 for further Arkansas by SWEPCo in September 1999. See discussion of changes in our communications Note 8, "Customer Choice and Industry related business and other business operations Restructuring for additional information. announced in 2002. Use of Estimates - The preparation of these Rate Regulation AEP is subject to regulation by financial statements in conformity with generally the SEC under the PUHCA. The rates charged accepted accounting principles necessarily by the domestic utility subsidiaries are approved includes the use of estimates and assumptions by by the FERC and the state utility commissions. management. Actual results could differ from The FERC regulates wholesale electricity those estimates. L-3
Property, Plant and Equipment Domestic Depreciation, Depletion and Amortization - electric utility property, plant and equipment are Depreciation of property, plant and equipment is stated at original cost of the acquirer. Property, provided on a straight-line basis over the plant and equipment of the non-regulated estimated useful lives of property, otherthan coal-operations and other investments are stated at mining property, and is calculated largely through their fair market value at acquisition plus the the use of composite rates by functional class as original cost of property acquired or constructed follows: since the acquisition, less disposals. Additions, Annual Composite major replacements and betterments are added to Functional Class Depreciation Rates of ProDertv Ranges the plant accounts. For cost-based rate-regulated 2002 operations, retirements from the plant accounts Production: Steam-Nuclear 2.5% to 3.4% and associated removal costs, net of salvage, are Steam-Fossil -Fi red 2.6% to 4.5% deducted from accumulated depreciation. The Hydroelectric- conventional and Pumped Storage 1.9% to 3.4% costs of labor, materials and overhead incurred to Transmission 1.7% to 3.0% operate and maintain plant are included in Distribution 3.3% to 4.2% other 1.8% to 9.9% operating expenses. Plants are tested for Annual Composite impairment as required under SFAS 144. See Functional class Depreciation Rates Note 13. of ProDerty Ranges 2001 Production: Allowance for Funds Used During Construction Steam-Nuclear 2.5% to 3.4% Steam-Fossil-Fired 2.5% to 4.5% (AFUDC) and Interest Capitalization -AFUDC is a Hydroelectric- conventional and Pumped Storage 1.9% to 3.4% noncash, nonoperating income item that is Transmission 1.7% to 3.1% capitalized and recovered through depreciation Distribution other 2.7% 1.8% to 4.2% to 15.0% over the service life of domestic regulated electric utility plant. It represents the estimated cost of Annual Composite Functional class Depreciation Rates borrowed and equity funds used to finance of ProDerty Ranges 2000 construction projects. The amounts of AFUDC for Production: 2002, 2001 and 2000 were not significant. Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 2.3% to 4.5% Effective with the discontinuance of SFAS 71 Hydroelectric- conventional regulatory accounting for domestic generating and Pumped Storage Transmission 1.9% 1.7% to to 3.4% 3.1% assets in Arkansas, Ohio, Texas, Virginia, West Distribution 3.3% to 4.2% Virginia and other non-regulated operations, other 2.5% to 7.3% 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. 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 3.5% 2.8% APCo 3.4 2.9 2.2 3.3 3.1 CSPco 3.2 2.3 3.6 3.2 I&M 3.4 4.5 3.4 1.9 4.2 3.8 KPCo 3.8 1.7 3.5 2.5 OPCo 3.4 2. 7 2.3 4.0 2.7 PSO 2.7 2.3 3.4 6.3 SWEPCo 3.4 2.7 3.6 4.7 TCC 2.5 2.6 1.9 2.3 3.5 4.0 TNC 2.8 3.1 3.3 6.8 Depreciation, depletion and amortization of coal- as described in the New Accounting mining assets is provided over each asset's Pronouncements section of Note 1, natural gas estimated useful life or the estimated life of the inventories held in connection with trading mine, whichever is shorter, and is calculated operations at October 25, 2002 continued to be using the straight-line method for mining carried atfairvalue until December31,2002, and structures and equipment. The units-of- inventory purchased from October 26 through production method is used to amortize coal rights December 31, 2002 was carried at the lower of and mine development costs based on estimated cost or market. Effective January 1, 2003, all recoverable tonnages. These costs are included natural gas inventories held in connection with in the cost of coal charged to fuel expense for trading operations will be adjusted to the historical coal used by utility operations. Current average cost basis and carried at the lower of cost or amortization rates are $0.32 per ton in 2002, market. We estimate the adjustment in January $3.46 per ton in 2001 and $5.07 per ton in 2000. 2003 will decrease the value of natural gas In 2001, an AEP subsidiary sold coal mines in inventories held in connection with trading Ohio and West Virginia. See Note 12, operations by approximately $39 million. This Acquisitions, Dispositions and Discontinued change will be accounted for as a cumulative Operations for further discussion of the changes effect of a change in accounting principle. in our coal investments leading to the decline in amortization rates in 2002. Accounts Receivable AEP Credit, Inc. factors accounts receivable for certain of the domestic Cash and Cash Equivalents - Cash and cash utility subsidiaries and, until the first quarter of equivalents include temporary cash investments 2002, factored accounts receivable for certain with original maturities of three months or less. non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into asale of receivables Inventory Except for PSO, TCC and TNC, the agreementwith a group of banks and commercial regulated domestic utility companies value fossil paper conduits. This transaction constitutes a fuel inventories using a weighted average cost sale of receivables in accordance with SFAS 140, method. PSO, TCC and TNC, utilize the LIFO allowing the receivables to be taken off of the method to value fossil fuel inventories. For those companys balance sheet. See Note 23 for domestic utilities whose generation is further details. unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories Foreign Currency Translation - The financial are also carried at the lower of cost or market. statements of subsidiaries outside the U.S. which Materials and supplies inventories are carried at are included in AEP s consolidated financial average cost. statements are measured using the local currency as the functional currency and translated into U.S. Non-trading gas inventory is carried at the lower dollars in accordance with SFAS 52 "Foreign of cost or market. In compliance with EITF 02-03 Currency Translation . Assets and liabilities are L-5
translated to U.S. dollars at year-end rates of financial statements of AEP and the financial exchange and revenues and expenses are statements of electric operating subsidiary translated at monthly average exchange rates companies with cost-based rate-regulated throughout the year. Currency translation gain operations (I&M, KPCo, PSO, and a portion of and loss adjustments are recorded in APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), shareholders' equity as Accumulated Other reflect the actions of regulators that can result in Comprehensive Income (Loss). The non-cash the recognition of revenues and expenses in impact of the changes in exchange rates on cash, different time periods than enterprises that are not resulting from the translation of items at different rate regulated. In accordance with SFAS 71, exchange rates, is shown on AEP s Consolidated regulatory assets (deferred expenses to be Statements of Cash Flows in Effect of Exchange recovered in the future) and regulatory liabilities Rate Changes on Cash. Actual currency (deferred future revenue reductions or refunds) transaction gains and losses are recorded in are recorded to reflect the economic effects of income. regulation by matching expenses with their recoverythrough regulated revenues in the same Deferred Fuel Costs - The cost of fuel consumed accounting period and by matching income with is charged to expense when the fuel is burned. its passage to customers through regulated Where applicable under governing state revenues in the same accounting period. regulatory commission retail rate orders, fuel cost Regulatory liabilities are also recorded to provide over or under-recoveries are deferred as currently for refunds to customers that have not regulatory liabilities or regulatory assets in yet been made. accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to When regulatory assets are probable of recovery customers in later months with the regulators through regulated rates, we record them as review and approval. The amount of deferred fuel assets on the balance sheet. We test for costs under fuel clauses forAEP was $143 million probability of recovery whenever new events at December 31, 2002 and $139 million at occur, for example a regulatory commission order December 31, 2001. See Note 7 "Effects of or passage of new legislation. If we determine Regulation . that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a We are protected from fuel cost changes in charge against net income. A write off of Kentucky for KPCo, the SPP area of Texas, regulatory assets may also reduce future cash Louisiana and Arkansas for SWEPCo, Oklahoma flows since there may be no recovery through for PSO and Virginia for APCo. Where fuel regulated rates. clauses have been eliminated due to the transition to market pricing, (Ohio effective Traditional Electricity Supply and Deliverv January 1, 2001 and in the Texas ERCOT area Activities - Revenues are recognized on the effective January 1, 2002) changes in fuel costs accrual or settlement basis for normal retail and impact earnings. In other state jurisdictions, wholesale electricity supply sales and electricity (Indiana, Michigan and West Virginia) where fuel transmission and distribution delivery services. clauses have been frozen or suspended for a The revenues are recognized in our income period of years, fuel cost changes also impact statement when the energy is delivered to the earnings. This is also true for certain of AEP s customer and include unbilled as well as billed Independent Power Producer generating units amounts. In general, expenses are recorded that do not have long-term contracts for their fuel when purchased electricity is received and when supply. See Note 6, "Rate Matters and Note 8, expenses are incurred. "Customer Choice and Industry Restructuring for further information about fuel recovery. Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas Revenue Recognition - pipeline and storage services when gas is delivered to contractual meter points or when Regulatory Accountinq - The consolidated services are provided. Transportation and L-6
storage revenues also include the accrual of area, the total gain or loss realized in cash for earned, but unbilled andlor not yet metered gas. sales and the cost of purchased energy are included in revenues on a net basis. Prior to Substantially all of the forward gas purchase and settlement, changes in the fair value of physical sale contracts, excluding wellhead purchases of forward sale and purchase contracts in AEP s natural gas, swaps and options for the domestic traditional marketing area are deferred as pipeline operations, qualify as derivative financial regulatory liabilities (gains) or regulatory assets instruments as defined by SFAS 133. (losses). For contracts with delivery points Accordingly, net gains and losses resulting from outside of AEP s traditional marketing area only revaluation of these contacts to fair value during the difference between the accumulated the period are recognized currently in the results unrealized net gains or losses recorded in prior of operations, appropriately discounted and net of periods and the cash proceeds is recognized in applicable credit and liquidity reserves. the income statement as nonoperating income. Prior to settlement, changes in the fair value of Energy Marketinq and Trading Transactions physical forward sale and purchase contracts with In 2000, 2001 and throughout the majority of delivery points outside of AEP s traditional 2002, AEP engaged in wholesale electricity, marketing area are included in nonoperating natural gas and other commodity marketing and income on a net basis. Unrealized mark-to-trading transactions (trading activities). Trading market gains and losses are included in the activities involve the purchase and sale of energy Balance Sheet as energy trading contract assets under forward contracts at fixed and variable or liabilities as appropriate. prices and the trading of financial energy contracts which includes exchange futures and For APCo, CSPCo and OPCo, depending on options and over-the-counter options and swaps. whether the delivery point for the electricity is in We use the mark-to-market method of accounting AEP s traditional marketing area or not for trading activities as required by EITF Issue No. determines where the contract is reported in the 98-10, "Accounting for Contracts Involved in income statement. Physical forward trading sale Energy Trading and Risk Management Activities and purchase contracts with delivery points in (EITF 98-10). Under the mark-to-market method AEP s traditional marketing area are included in of accounting, gains and losses from settlements revenues on a net basis. Prior to settlement, of forward trading contracts are recorded net in changes in the fair value of physical forward sale revenues. For energy contracts not yet settled, and purchase contracts in AEP s traditional whether physical or financial, changes in fair marketing area are also included in revenues on a value are recorded net in revenues as unrealized net basis. Physical forward sale and purchase gains and losses from mark-to-marketvaluations. contracts for delivery outside of AEP s traditional When positions are settled and gains and losses marketing area are included in nonoperating are realized, the previously recorded unrealized income when the contract settles. Prior to gains and losses from mark-to-market valuations settlement, changes in the fair value of physical are reversed. In October 2002, management forward sale and purchase contracts with delivery announced plans to focus on wholesale markets points outside of AEP s traditional marketing area around owned assets. are included in nonoperating income on a net basis. All of the registrant subsidiaries except AEGCo participate in AEP s wholesale marketing and The trading of energy options, futures and swaps, trading of electricity. For l&M, KPCo, PSO and a represents financial transactions with unrealized portion of TNC and SWEPCo, when the contract gains and losses from changes in fair values settles the total gain or loss is realized in cash. reported net in AEP s revenues until the contracts Where this amount is recorded on the income settle. When these contracts settle, the net statement depends on whether the contract s proceeds are recorded in revenues and reverse delivery points are within or outside of AEP s the prior cumulative unrealized net gain or loss. traditional marketing area. For contracts with APCo, CSPCo, OPCo, I&M and KPCo also have delivery points in AEP s traditional marketing financial transactions, but record the unrealized L-7
gains and losses, as well as the net proceeds the cost of debt to be issued. These anticipatory upon settlement, in nonoperating income. debt instruments are entered into in order to manage the change in interest rates between the The fair values of open short-term trading time a debt offering is initiated and the issuance contracts are based on exchange prices and of the debt (usually a period of 60 days). Gains or broker quotes. Open long-term trading contracts losses from these transactions are deferred and are marked-to-market based mainly on AEP- amortized over the life of the debt issuance with developed valuation models. The models are the amortization included in interest charges. derived from internally assessed market prices There were no such forward contracts with the exception of the NYMEX gas curve, outstanding at December 31, 2002 or 2001. See where we use daily settled prices. All fair value Note 17 'Risk Management, Financial amounts are net of appropriate valuation Instruments and Derivatives for further adjustments for items such as discounting, discussion of the accounting for risk management liquidity and credit quality. Such valuation transactions. adjustments provide for a better approximation of fair value. The use of these models to fair value Levelization of Nuclear Refueling Outage Costs - open trading contracts has inherent risks relating In order to match costs with regulated revenues, to the underlying assumptions employed by such incremental operation and maintenance costs models. Independent controls are in place to associated with periodic refueling outages at evaluate the reasonableness of the price curve I&M s Cook Plant are deferred and amortized over models. Significant adverse or favorable effects the period beginning with the commencement of on future results of operations and cash flows an outage and 'ending with the beginning of the could occur if market prices, at the time of next outage. settlement, do not correlate with AEP-developed price models. Maintenance Costs Maintenance costs are expensed as incurred except where SFAS 71 As explained above, the effect on AEP s requires the recordation of a regulatory asset to Consolidated Statements of Operations of match the expensing of maintenance costs with marking to market open electricity trading their recovery in cost-based regulated revenues. contracts in AEP s regulated jurisdictions is See below for an explanation of costs deferred in deferred as regulatory assets (losses) or liabilities connection with an extended outage at l&M s (gains) since these transactions are included in Cook Plant. cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market Amortization of Cook Plant Deferred Restart gains and losses from trading activities whether Costs - Pursuant to settlement agreements deferred or recognized in revenues are part of approved by the IURC and the MPSC to resolve Energy Trading and Derivative Contracts assets all issues related to an extended outage of the or liabilities as appropriate. Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs Construction Projects for Outside Parties during 1999. The deferred amount is being Certain AEP entities engage in construction amortized to expense on a straight-line basis over projects for outside parties that are accounted for five years from January 1, 1999 to December 31, on the percentage-of-completion method of 2003. I&M amortized $40 million each year 1999 revenue recognition. This method recognizes through 2002 leaving $40 million as an SFAS 71 revenue in proportion to costs incurred compared regulatory asset at December 31, 2002 on the to total estimated costs. Consolidated Balance Sheets of AEP and l&M. Debt InstrumentHedging and RelatedActivities Other Income and Other Expenses Other In order to mitigate the risks of market price and Income includes non-operational revenue interest rate fluctuations, AEP, APCo, CSPCo, including area business development and river I&M, KPCo and OPCo enter into contracts to transportation, equity earnings of non-manage the exposure to unfavorable changes in consolidated subsidiaries, gains on dispositions of L-8
property, interest and dividends, an allowance for amortized over the life of the regulated plant equity funds used during construction (explained investment. above) and miscellaneous income. Other Expenses includes non-operational expense Excise Taxes AEP and its subsidiary including area business development and river registrants, as an agent for a state or local transportation, losses on dispositions of property, government, collect from customers certain miscellaneous amortization, donations and excise taxes levied by the state or local various other non-operating and miscellaneous government upon the customer. These taxes are expenses. not recorded as revenue or expense, but only as a pass-through billing to the customer to be AEP Consolidated other Income and Deductions remitted to the government entity. Excise tax December 31, collections and payments related to taxes 2002 2001 2000 imposed upon the customer are not presented in (in millions) OTHER INCOME: the income statement. Equity Earnings S 104 S 123 $ 22 Non-operational Revenue 187 123 71 Interest and Debt and Preferred Stock Gains and losses Miscellaneous Income 25 16 2 from the reacquisition of debt used to finance Gain on sale of Frontera Gain on sale of Retail 73
- - domestic regulated electric utility plant are Electric Provider 129 - - generally deferred and amortized over the Total other Income S 45 S- ___ remaining term of the reacquired debt in accordance with their rate-making treatment. If OTHER EXPENSES: debt associated with the regulated business is Property Taxes and Miscellaneous Expenses S 142 S 68 5 28 refinanced, the reacquisition costs attributable to Non-operational Expenses 179 56 49 the portions of the business that are subject to Fiber optic and - 49 - cost based regulatory accounting under SFAS 71 Datapult Exit Costs Provision for Loss - are generally deferred and amortized over the Airplane - 14 term of the replacement debt commensurate with Total other Expenses S1321 s1&z Lz their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to Income Taxes - The AEEP System follows the SFAS 71 are reported as a Loss on Reacquired liability method of accoun ting for income taxes as Debt, an extraordinary item on the Consolidated prescribed by SFAS 109, lAccounting for Income Statements of Operations of AEP and TCC. See Taxes. Under the liat iility method, deferred discussion of SFAS 145 in New Accounting income taxes are provi'ded for all temporary Pronouncements section of this note for new differences between the Ibook cost and tax basis treatment effective in 2003.
of assets and liabilities which will result in a future tax consequence. Where the flow-through Debt discount or premium and debt issuance method of accounting for temporary differences is expenses are deferred and amortized utilizing the reflected in regulated revenues (that is, deferred effective interest rate method over the term of the taxes are not included in the cost of service for related debt. The amortization expense is determining regulated rates for electricity), included in interest charges. deferred income taxes are recorded and related regulatory assets and liabilities are established in Where rates are regulated, redemption premiums accordance with SFAS 71 to match the regulated paid to reacquire preferred stock of the domestic revenues and tax expense. utility subsidiaries are included in paid-in capital and amortized to retained earnings Investment Tax Credits - Investment tax credits commensurate with their recovery in rates. The have been accounted for under the flow-through excess of par value over costs of preferred stock method except where regulatory commissions reacquired is credited to paid-in capital and have reflected investment tax credits in the rate- amortized to retained earnings consistentwith the making process on a deferral basis. Investment timing of its inclusion in rates in accordance with tax credits that have been deferred are being SFAS 71. L-9
Goodwill and Intangible Assets In June 2001, Nuclear Trust Funds Nuclear decommissioning the FASB issued SFAS 141, Business and spent nuclear fuel trust funds represent funds Combinations, and SFAS 142, Goodwill and that regulatory commissions have allowed us to Other Intangible Assets, affecting AEP and collect through rates to fund future SWEPCo. decommissioning and spent fuel disposal liabilities. By rules or orders, the state SFAS 141 requires that the purchase method of jurisdictional commissions (Indiana, Michigan and accounting be used for all business combinations Texas) and the FERC established investment initiated after June 30,2001 and established new limitations and general risk management standards for the recognition of certain identifiable guidelines to protect their ratepayers funds and to intangible assets, separate from goodwill. We allow those funds to earn a reasonable return. In adopted the provisions of SFAS 141 effective July general, limitations include: 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note . Acceptable investments (rated investment 3 for further discussion of our components of grade or above) goodwill and intangible assets.
- Maximum percentage invested in a specific type of investment SFAS 142 requires that goodwill and intangible
- Prohibition of investment in obligations of the assets with finite useful lives no longer be applicable company or its affiliates.
amortized, but instead tested for impairment at least annually. SFAS 142 also requires that Trust funds are maintained for each regulatory intangible assets with finite useful lives be jurisdiction and managed by investment amortized over their respective estimated lives to managers, who must comply with the guidelines the estimated residual values. In accordance with and rules of the applicable regulatory authorities. SFAS 142, for all business combinations with an The trust assets are invested in order to optimize acquisition date before July 1,2001, we amortized the after-tax earnings of the Trust, giving goodwill and intangible assets with indefinite lives consideration to liquidity, risk, diversification, and through December 2001, and then ceased other prudent investment objectives. amortization. The goodwill associated with those business combinations with an acquisition date Securities held in trust funds for decommissioning before July 1, 2001 was amortized on a straight- nuclear facilities and for the disposal of spent line basis generally over 40 years except for the nuclear fuel are included in Other Assets at portion of goodwill associated with gas trading market value in accordance with SFAS 115, and marketing activities which was amortized on a "Accounting for Certain Investments in Debt and straight-line basis over 10 years. In accordance Equity Securities. Securities in the trust funds with SFAS 142, for all business combinations with have been classified as available-for-sale due to an acquisition date after June 30, 2001, we have their long-term purpose. Inaccordance with SFAS not amortized goodwill and intangible assets with 71, unrealized gains and losses from securities in indefinite lives. Intangible assets with finite lives these trust funds are not reported in equity but continue to be amortized over their respective result in adjustments to the liabilityaccount forthe estimated lives ranging from 5 to 10 years. See nuclear decommissioning trust funds and to Note 3 for total goodwill, accumulated regulatory assets or liabilities for the spent nuclear amortization and the impact on operations of the fuel disposal trust funds in accordance with their adoption of SFAS 142. treatment in rates. In early 2002, we began testing our goodwill and Comprehensive Income (Loss) - Comprehensive intangible assets with indefinite useful lives for income (loss) is defined as the change in equity impairment, in accordance with SFAS 142. See (net assets) of a business enterprise during a Note 3 for the results of our testing and the period from transactions and other, events and corresponding net transitional impairment loss circumstances from non-owner sources. It recorded as a Cumulative Effect of Accounting includes all changes in equity during a period Change during 2002. except those resulting from investments by L-1 0
owners and distributions to owners. segment as viewed by the chief operating Comprehensive income (loss) has two decision-maker. See Note 16, "Business components: net income (loss) and other Segments for further discussion and details comprehensive income (loss). There were no regarding segments. material differences between net income and comprehensive income for AEGCo. Common Stock Options At December 31, 2002, AEP has two stock-based employee Components of Other Comprehensive Income compensation plans with outstanding stock (Loss) Other comprehensive income (loss) is options, which are described more fully in Note included on the balance sheet in the equity 15. AEP accounts for these plans under the section. The following table provides the recognition and measurement principles of APB components that comprise the balance sheet Opinion No. 25, Accounting for Stock Issued to amount in Accumulated Other Comprehensive Employees and related Interpretations. No stock-Income (Loss) for AEP. based employee compensation expense is reflected in AEP s earnings, as all options granted under these plans had exercise prices equal to or December 31, above the marketvalue of the underlying common 2002 2001 2000 (in millions) stock on the date of grant. The following table Foreign Currency Adjustments S 4 S(113) S (99) illustrates the effect on AEP s net income (loss) unrealized Losses (2) - - and earnings (loss) per share as if AEP had on Securities unrealized Gain on applied the fair value recognition provisions of Hedged Derivatives Minimum Pension (16) (3) - FASB Statement No. 123, "Accounting for Stock-Liability Based Compensation , to stock-based employee (595) (c ) (4) compensation. Year Ended December 31, Accumulated Other Comprehensive Income 2002 2001 2000 (Loss) for AEP registrant subsidiaries as of (in millions except per share data) December 31, 2002 and 2001 is shown in the Net Income(Loss), as reported $ (519) S 971 $ 267 following table. Registrant subsidiary balances Deduct: Total stock-for Accumulated Other Comprehensive Income based employee compensation (Loss) for the year ended December 31, 2000 expense determined was zero. under fair value based method for all awards, net of December 31, related tax effects (12) components 2002 2001 Pro forma net income L__) LZ34 (in thousands) (loss) 5Th57) S-95 5.3 0 cash Flow Hedges: APCO S(1,920) S (340) Earnings (Loss) per cSPco (267) share: I&M (286) (3,835) Basic as reported S-UI5) S2Z97 SO. S3 KPCo 322 (1,903) Basic pro forma oPco (738) (196) PSO (42) Diluted _____) SIZAZg OM18 SWEPCo (48) as reported TCC (36) Diluted pro forma TNC (15) Minimum Pension Liability: Earnings Per Share (EPS) AEP calculates APCO S(70,162) earnings (loss) per share in accordance with cSPco (59,090) INM (40,201) SFAS No. 128, "Earnings Per Share (see Note KPCO (9,773) oPco (72,148) 19). Basic earnings (loss) per common share is PSO SWEPCo (54,431) (53,635) calculated bydividing neteamings (loss) available TCC (73,124) to common shareholders by the weighted average TNC (30,748) number of common shares outstanding during the'- period. Diluted earnings (loss) per common share Segment Reporting The AEP System has is calculated by adjusting the weighted average adopted SFAS No. 131, which requires disclosure outstanding common shares, assuming of selected financial information by business L-1 I
conversion of all potentially dilutive stock options recent market transactions and cash flow and awards. The effects of stock options have projections. As a result of that testing, AEP not been included in the fiscal 2002 diluted loss determined that there was a net transitional per common share calculation as their effect impairment loss, which is reported as a would have been anti-dilutive. Basic and diluted cumulative effect of a change in accounting EPS are the same in 2002, 2001 and 2000. principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, sales of impaired assets. SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report SFAS 142 also changed the accounting and EPS. reporting for goodwill and other intangible assets. In accordance with SFAS 142 goodwill and Reclassification Beginning in the fourth quarter indefinite lived intangible assets acquired through of 2002, AEP and its registrant subsidiaries acquisition after June 30, 2001 were not elected to begin netting certain assets and amortized. Effective January 1, 2002, liabilities related to forward physical and financial amortization related to goodwill and indefinite transactions. This is done in accordance with lived intangible assets acquired before July 1, FASB Interpretation No. 39, "Offsetting of 2001 ceased. SFAS 142 requires that other Amounts Related to Certain Contracts and intangible assets be separately identified and if Emerging Issues Task Force Topic D-43, they have finite lives, they must be amortized over "Assurance That a Right of Setoff is Enforceable that life. See Note 3 for amortization lives of in a Bankruptcy under FASB Interpretation No. AEP s and SWEPCo s intangible assets. 39 . Transactions with common counterparties have been netted at the applicable entity level, by SFAS 143, "Accounting for Asset Retirement commodity and type (physical or financial) where Obligations , is effective for AEP on January 1, the legal right of offset exists. For comparability 2003. SFAS 143 generally applies to legal purposes, prior periods presented in this report obligations associated with the retirement of long-have been netted in accordance with this policy. lived assets. A company is required to recognize an estimated liability for any legal obligations Certain additional prior year financial statement associated with the future retirement of its long-items have been reclassified to conform to current lived assets. The liability is measured atfairvalue year presentation. Such reclassifications had no and is capitalized as part of the related assets impact on previously reported net income. capitalized cost. The increase in the capitalized cost is included in determining depreciation New Accounting Pronouncements expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 SFAS 142, "Goodwill and Other Intangible will be recorded as a cumulative effect of an Assets, was effective for AEP on January 1, accounting change. Additionally, because the 2002. The adoption of SFAS 142 required the asset retirement obligation is recorded initially at transition testing for impairment of all indefinite fair value, accretion expense (similar to interest) lived intangibles by the end of the first quarter will be recognized each period as an operating 2002 and initial testing of goodwill by the end of expense in the statement of operations. the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its The regulated entities have an asset retirement domestic operations and its indefinite lived obligation associated with nuclear intangible assets and there was no impairment. decommissioning costs for the Cook and STP Inthe second quarter 2002, AEP completed initial Nuclear Plants (affects l&M and TCC) and testing for goodwill impairment of the U.K. and possibly other obligations. AEP expects to Australian retail electricity and supply operations. establish regulatory assets and liabilities that will The fair values of the U.K. and Australia retail result in no cumulative effect adjustment of electricity and supply operations were estimated adopting SFAS 143 for the regulated entities. using a combination of market values based on L-1 2
In addition, the regulated transmission and 121, "Accounting for Long-lived Assets and for distribution entities have asset retirement Long-lived Assets to be Disposed Of. AEP obligations related to the final retirement of certain adopted SFAS 144 effective January 1, 2002. transmission and distribution lines. There are The adoption of SFAS 144 did not materially also underground storage tanks located at various affect AEP s results of operations or financial sites throughout the AEP System and PCB s are conditions. See Notes 3 and 13 for discussion of contained in certain transformer rectifier sets at impairments recognized in 2002 by AEP and its power plants. The amounts relating to these registrant subsidiaries, affected by SFAS 144. obligations cannot be determined because the entities are not able to estimate the final In April 2002, the FASB issued SFAS 145, retirement dates for these facilities. "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and In January 2003, the SEC Staff concluded that Technical Corrections'. SFAS 145 rescinds SFAS 143 also precludes an entity from recording SFAS 4, "Reporting Gains and Losses from an expense for estimated costs associated with Extinguishment of Debt", effective for fiscal years the removal or retirement of assets that result beginning after May 15, 2002. SFAS 4 required from other than legal obligations. The SEC Staff gains and losses from extinguishment of debt to concluded that amounts that are included in be aggregated and classified as an extraordinary accumulated depreciation related to estimated item if material. In 2003, for financial reporting removal costs arising from other than legal purposes AEP and TCC will reclassify obligations should be written off as part of the extraordinary losses net of tax on TCC s cumulative effect of adopting SFAS 143 unless reacquired debt of $2 million for 2001. the company is regulated under SFAS 71. Companies regulated under SFAS 71 may In October2002, the Emerging Issues Task Force continue to include removal costs in depreciation of the FASB reached a final consensus on Issue rates but must quantify the removal costs No. 02-3, "Recognition and Reporting of Gains included in accumulated depreciation as and Losses on Energy Contracts under Issues regulatory liabilities in footnote disclosure. The No. 98-10 and 00-17 (EITF 02-3). EITF 02-3 AEP registrant subsidiaries that are regulated rescinds EITF 98-10 and related interpretive entities have included estimated removal costs for guidance. Under EITF 02-3, mark-to-market non-legal retirement obligations in book accounting is precluded for energy trading depreciation rates. contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 For non-regulated entities, including certain will also eliminate any basis for recognizing formerly regulated generation facilities, asset physical inventories at fair value other than as retirement obligations associated with wind farms, provided by generally accepted accounting closure costs associated with power plants in the principles. The consensus is effective for fiscal U.K. and possibly other items will be incurred. periods beginning after December 15, 2002, and Also the amount of removal costs embedded in applies to all energy trading contracts entered into accumulated depreciation is expected to result in and inventory purchased through October 25, a favorable cumulative effect adjustment to net 2002. Effective January 1, 2003, nonderivative income. However, AEP and its registrant energy contracts are required to be accounted for subsidiaries have not completed their on a settlement basis and inventory is required to determination of the net effect of these items on be presented at the lower of cost or market. The first quarter 2003 results of operations upon the effect of implementing this consensus will be adoption of the provisions of this standard. reported as a cumulative effect of an accounting change. Such contracts and inventory will In August 2001, the FASB issued SFAS 144, continue to be accounted for at fair value through "Accounting for the Impairment or Disposal of December 31,2002. Energycontracts that qualify Long-lived Assets which sets forth the as derivatives will continue to be accounted for at accounting to recognize and measure an fair value under SFAS 133. impairment loss. This standard replaced, SFAS L-1 3
Effective January 1,2003, EITF 02-3 requires that initially be measured and recorded at fair value. gains and losses on all derivatives, whether The timing of recognizing future costs related to settled financially or physically, be reported in the exit or disposal activities, including restructuring, income statement on a net basis if the derivatives as well as the amounts recognized may be are held for trading purposes. Previous guidance affected by SFAS 146. AEP will adopt the in EITF 98-10 permitted non-financial settled provisions of SFAS 146 for exit or disposal energy trading contracts to be reported either activities initiated after December 31, 2002. gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant In November 2002, the FASB issued subsidiaries recorded and reported upon Interpretation No. 45, "Guarantors Accounting settlement, sales under forward trading contracts and Disclosure Requirements for Guarantees, as revenues and purchases under forward trading Including Indirect Guarantees of Indebtedness of contracts as purchased energy expenses. Others (FIN 45) which requires that a liability Effective July 1, 2002, AEP and its registrant related to issuing a guarantee be recognized, as subsidiaries reclassified such forward trading well as additional disclosures of guarantees. revenues and purchases on a net basis, as This new guidance is an interpretation of SFAS permitted by EITF 98-10. The reclassification of Nos. 5, 57 and 107 and a rescission of FIN No. such trading activity to a net basis of reporting 34. The initial recognition and initial resulted in a substantial reduction in both measurement provisions of FIN 45 are effective revenues and purchased energy expense, but did on a prospective basis to guarantees issued or not have any impact on financial condition, results modified after December 31, 2002. The of operations or cash flows. disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods Effective July 1, 2002, AEP and its registrant ending after December 15, 2002. We do not subsidiaries modified their valuation procedures expect that the implementation of FIN 45 will for estimating the fair value of energy trading materially affect results of operations, cash flows contracts at inception. Unrealized gain or loss at or financial condition. See guarantee details inception is recognized only when the fair value of discussed in Note 10. a contract is obtained from a quoted market price in an active market or is otherwise evidenced by In December 2002, the FASB issued SFAS No. comparison to other observable market data. Any 148, "Accounting for Stock-Based Compensation-fair value changes subsequent to the inception of Transition and Disclosure , which amends SFAS a contract, however, are recognized immediately No. 123, "Accounting for Stock-Based based on the best market data available. AEP Compensation . SFAS 148 provides alternative and its registrant subsidiaries now also use such methods of transition for a voluntary change to procedures for determining unrealized gain or the fair value based method of accounting for loss at inception for all derivative contracts. stock-based employee compensation. Underthe fair value based method, compensation cost for In June 2002, FASB issued SFAS 146 which stock options is measured when options are addresses accounting for costs associated with issued. In addition, SFAS 148 amends the exit or disposal activities. This statement disclosure requirements of SFAS 123 to require supersedes previous accounting guidance, more prominent and more frequent (quarterly) principally EITF No. 94-3, "Liability Recognition for disclosures in financial statements of the effects Certain Employee Termination Benefits and Other of stock-based compensation. SFAS 148 is Costs to Exit an Activity (including Certain Costs effective for fiscal years ending after December Incurred in a Restructuring). Under EITF No. 94- 15, 2002. AEP does not currently intend to adopt 3, a liability for an exit cost was recognized at the the fair value based method of accounting for date of an entitys commitment to an exit plan. stock options. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be In November2002, the FASB issued an Invitation recognized when the liability is incurred. SFAS to Comment, "Accounting for Stock-Based 146 also establishes that the liability should 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 10CFR50.71 (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 10CFR50.71 (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 10-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 10-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 NOC-AE-31659820 File No.: G20 Page 2 cc: (paper copy) (electronic copy) Regional Administrator, Region IV A. H. Gutterman, Esquire U. S. Nuclear Regulatory Commission Morgan, Lewis & Bockius LLP 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011 -8064 L. D. Blaylock City Public Service U. S. Nuclear Regulatory Commission David H. Jaffe Attention: Document Control Desk U. S. Nuclear Regulatory One White Flint North Commission 11555 Rockville Pike Rockville, MD 20852 R. L. Balcom Texas Genco, LP Richard A. Ratliff A. Ramirez Bureau of Radiation Control City of Austin Texas Department of Health 11 00 West 49th Street C. A. Johnson Austin, TX 78756-3189 AEP Texas Central Company Jeffrey Cruz Jon C. Wood U. S. Nuclear Regulatory Commission Matthews & Branscomb P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 F. H. Mallen, w/o N5001 G. Harrison, w/o N5001 R. G. Hyde, w/o N5001 R. D. Piggott, w/o N5014 S. C. Beaver N5014 RMS N2002 File
AAERiICAN t ELECURJ I FP3Wly t r I r I
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I .,- Z*-L-Il r, I r-iiil 'I i -i rwjrr 3/4 Ic I 2/
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2002 - 2001 C h an g&
-Net Income (Loss) (in millions) .
ongoing
' -- - - - ~~$95.7 $1,087-,
as reported'. - S(l19 (519) $971 (153.50 Earnings (Loss) Per Share *- - , -
- ngoing -- .-.. - S89$3.38: -(4~
as reported - 1157] $3.01 (1_2 Revenues billions) o-(in - $14 6 $12.8 -i.
--~Cash Dividends - $2.40 $2.40,
- Year*EndClos~~~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 - 23,4 (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-- adjustment ~~for curring 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 -ofand 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 '- resructurngplan, 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 - - Qmu.
- r. Writing down the value of poorly difficult for AEP. Due to performing investments contributed to a variety of factors, our earn- charges of approximately $1.5 billion ings fell dramatically, as did our for 2002. Some of these write-offs, stock price. We deeply regret that such as those related to telecommu-our performance was far below our nications assets, were anticipated.
goals and your expectations. Others, such as a $415 million charge related to our generation assets in the In response to the negative United Kingdom, were not. We also developments in 2002, we are taking incurred an equity reduction of nearly decisive steps to strengthen our bal- $600 million because of lost value in ance sheet and put the company back our pension plan assets. While the on track for value growth. We remain latter event lowered the equity on our dedicated to providing low-cost electricity, superior balance sheet, the other items also reduced the earnings customer service and an attractive return to investors. on our income statement. A look back: Disappointing results On the positive side, despite last year's very tough market, Our utility operations performed reasonably well in we strengthened our balance sheet by $2 billion. We did it 2002 despite rising costs, but the withering of wholesale by selling non-core assets and issuing additional common markets in the U.S. and abroad cut into earnings from stock and equity units. In 2002 we completed the sale of our wholesale operations. As I'm sure you're aware, the SEEBOARD, a regional electric company in the UK, and wholesale arena - including power generation, associated CitiPower, an Australian electricity provider. AEP's first assets and related marketing activity - had been highly visit to the equity market in 20 years occurred last spring. profitable for us the past couple of years. Cash proceeds of approximately $1.1 billion from thei asset sales and $990 million from the issuance of common AEP's ongoing earnings totaled $2.89 per share in stock and equity units were used to pay down debt. 2002 compared with $3.38 in 2001. As-reported earnings were negative $1.57 per share, down from $3.01 the We did not attain our capitalization goal for 2002 of previous year. 45 percent equity and 55 percent debt but we expect to-
make significant progress this year. 2002 Sharehbolder Return executive management will not be paid 0 Our long-term goal is 50 percent to 55 this year. In addition, we expect to pare our percent debt. -5 capital expenditures forecast for this year by
.,i,:to $200 million, to $1.5 billion.
A look ahead: Focus on the basics *-15: In 2003, we will focus on the basics. We
- O decision to recommend a reduction in Our are returning to a more traditional model of a regulated utility with a small commercial I.; ......... -25 E:
the quarterly dividend of about 40 percent to our Board of Directors came after consid-group dedicated to maximizing the value of our generation fleet, which is the largest in
. I -30 erable analysis andw as painful but neces-sary. Reducing the dividend to a quarterly the United States. rate of 35 cents per share, starting with the
.40 :
J, 0Vsecond quarter, will result imannual cash S&P Electric AEP Currently, we think AEPs traditional utility Utlity Index S&P lndex ;savings of $340 million. This will imrnmedi-business perform at roughly the same 1will ............... ............. ately improve retained earnings and create level as last year and the wholesale business will have a free cash flow to boost liquidity and pay down debt. We somewhat weaker year. We project 2003 ongoing earnings believe the dividend will still have significant value and in the range of $2.20 to $2.40 per share, including the produce an attractive yield. dilution from additional equity issued in this year's cE: first quarter. We began shedding assets to improve our balance sheet CL last year and anticipate that process will accelerate in-- To bolster our balance sheet, we plan to lower costs, 2003. Non-core assets are the most likely candidates for E
-c ..reduce the quarterly dividend, dispose of additional non- divestment. This will be an orderly disposition. Proceeds-
- E
_q: core assets, maintain our liquidity and current lines of will go toward debt reduction. - - - - -E credit,'and maximize cash flow. Our liquidity position is strong. We have $3.5 billion CA: A company-wide cost reduction program should result in available in cash and credit facilities, and we had $1.2 oE0-- o sustainable net savings in operations and maintenance billion in cash at the, end of last year. During 2003, we a si
- . costs of approximately $60 millhon when compared with expect free cash flow of approximately $130 million after
~~~
w:¢: :i.: . i :: i0 E -: ..,:: i:: Ei :-:E
-i i~ E. . .. .. .. .. -i .E 2002 actual expenditures, and more than $300 million dividends are paid.- -
. 0..X -.T :0 when compared with previously projected 2003 expendi-E f: tures. We reduced our work force by approximately 1,300 In 2003, we aim for year-end capitalization consistent positions. Based on 2002 performance, bonuses for senior with a strong&BBB rating. We will continue to seek
opportunities for further debt reduction and to work 11-state service territory, thanks in part to increased usage with the rating agencies to ensure we're addressing by residential customers. their concerns.:.: AEP's Texas operations were a major contributor to last With deregulation at a standstill in much of our service year's utility-related earnings improvement. Customer ::` area,.we are re-evaluating our corporate separation choice was introduced in January 2002 in most-areas of initiative. The legal separation of our regulated and our Texas service territory. AEP's obligation to supply . unregulated businesses is provided for in Texas and Ohio,_ retail electric providers (REPs) in that state last year con-where generation is deregulated and customers in most tributed $495 million to gross margin. Sale of our affiliat-areas are able to choose their electricity supplier. ed REPs to Centrica, a leading retail energy provider, However, the cost savings and benefits for all customers near the end of 2002 provided immediate cash proceeds of: of a company-wide separation are now uncertain. We are $146 million. The transaction includes an arrangement exploring these issues with our regulators. Our intent is through 2006 that allows AEP. to share in any increased to comply'with restructuring legislation in the states that earnings opportunities that develop in the Texas retail provide for a legal separation and to maintain a functional: *market, protecting us against downside exposure. separation elsewhere.-- w Transmission represents a significant piece of our Even with deregulation stalled, many of the nearly 5 mil- regulated business. AEP, following Federal Energy lion customers linked to our Wires will benefit from rate Regulatory Commission (FERC) guidance, continues freezes in their respective states for the next severlS years.: working toward transferring functional control of its 38,000-mile transmission network to regioa transmis-Utility operations: Stable, predictable sion organizations, or RTOs. - .- AEPs regulated operations generate stable, reasonably predictable revenue and earnings. They have been a You may recall that AEP was among the companies steady contributor to our performance all along. The deeply involved in recent years in developing a proposed mission of our regulated business unit is to provide safe,: for-profit RTO called the Alliance. Last spring, however, 3 cost-effective and reliable service to customers. FERC turned down our proposal, so we are pursuing affil-lation with PJM Interconnection for our eastern assets and Ongoing earnings from utility operations in 2002 totaled the Midwest Independent System Operator in the west, '
$326 per, share, up from $39in 2001. Retail gross - At this point, we don't anticipate divesting our transmis-.
margins rose $250 million in Texas, $178 million in Ohio sion assets. We project RTO-related costs of $30 million i. and $91 million in other jurisdictions throughout AP's to $40 million in 2003.
Wholesale investments: Unmet expectations Energy marketing: Asset focus. Our unregulated operations performed well below our Most of the output of our generating units is committed projections in 2002. AEP's wholesale investments lost to our retail customers. The rest is marketed to other
$45 -million or 13 cents per share. Some of these utilities and wholesale customers.
investments, such as our natural gas and barge-line holdings, contributed positively to earnings, but the Our decision to greatly scale back our energy marketing UK generation we acquired in 2001 - the Fiddler's and trading operations and concentrate on' optimizing Ferry and Ferrybridge plants - posted a $59 million the value of our assets is reducing our risk exposure and operating loss. helping to preserve our creditrratings. Net margins from trading activities declined by'$349 million last year The UK has proved to be a very disappointing and because of our reduced activity and because earnings difficult market. The oversupply conditions worsened from trading in 2001 were exceptionally strong. C as the year progressed, particularly after the British gov-
'ernment decided'to subsidize British Energy. The $415 The outstanding net fair; value of trading contracts has million write-down of UK generation that I mentioned fallen from approximately $450 million to $250 millionA:0
- 1 earlier. stems, from recent analyses showing that UK over the past year. The average duration of our existing:-
power prices won't recover to levels that will support the trading book is year-end 2003 for gas and second-half 0 carrying value of the plants on our books at the original 2004 for power.--0 0 0 purchase price of roughly $1 billion. 0
-c Our risk management group continues to work closely U) 0 As I noted above, we will be looking to divest certain with the trading group to ensure limits are enforced.
a 0. 0 wholesale assets and the UK generation certainly will We reduced value-at-risk limits by 50 percent last year.. be considered. An even greater loss is possible in the S Environmental: Compliance and beyond::: S UK in 2003. We're evaluating the best way, to reduce U) N earnings drags and preserve shareholder value in Coal-fired generation remains AEP's mainstay. At the C 0 N this investment.l end of 2002, our generating capacity mix was 69 percent S coal and lignite, 20 p1ercent natural gas, 8 percent nuclear 0 0. U EOther unregulated investments not related to our whole- and 3 percent wind, hydro and other. U S sale business also fired poorly and are candidates for"
'Li i-divestment. Our telecommunications business had a $36.- Use of fossilfEels brings with it environmental expendi-'
S million operating loss. We are actively seeking buyers for tures, but our customer prices remain among the lowest'-` U E this business. in the regions where we operate.:
Our ongoing program to meet federal standards to con- Hagan, head of our shared services organization. Tomr: trol nitrogen oxide emissions'will cost an estimated ;$1.3 ' succeeded Joe' Vipperman, who retired last year after billion to $2 billion in capital expenditures. more than four decades of dedicated service. AEP remains a leader in policy discussions and research to Last year was indeed difficult and 2003 also holds address environmnental concerns. . ::many challenges. But I believe the measures I have outlined will improve our performance, and we are We are actively promoting enactment of legislation to 4 . C'committed to doing what it takes to rebuild the value further reduce sulfur dioxide, nitrogen oxide and mercury of your investment. 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:: E.Lin n Draper, Jr.. participating in a project, led by Battelle to assess Chairm~an, President &Chief Executive Officer
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whether deep injection of carbon dioxide into the earth February 28, 2003 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:
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AEP's strength, and our employees are our strongest :
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assets. Their dedication, talent and continued commit-0 -ment to our business mission are at the heart of our plan'
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0 C/) Stepping up to new duties last 'yearwere Holly, Koep - who was named to oversee our unregulated businesses: after the departure of Eric van der Walde; nd To m. .......
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
.... ....... d.. .. .............. ............... . . . . ..... . . . . . .. . q . . .
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 _______ TotalI . ... 341 1 __ _ E : Full disclosure 'of all Capitalization Ratio 2002 2001 o fina~ncial information o is included in the. .
'1 Long-Term De b-t ~~~~~~~~~~~~~~0.7% . 0.7%
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%:
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Revenues Expenses: 2002 S14,55 I 2001.
$12,767 f % Change:
Fuel and Purchased Eniergy -,6,307 4,944 Mainitenianceand Other Operation :. .. .:::~~::~: 3,710: Non-Recoverable Merger Costs':, .: 10 21
~~~~~~~~~~~............. ................ ..... ......
7 B67~~~~~~~~. .- Asset Impairments :; Depreciation and Amortization . 1,377 ~ 1,243 Taxes Othe r Than Income Taxes *718: 667: 1.7 Total Expenses 13,292 10,585 Other.Income . .. 445K! 335 Investment Value and Other.Imnpairment Losses 321 - N.m Other Expenses...... 321 j 187
.1,66. 2 2,330 Income Before Interest, Preferred Dividends. Minority Interest and Income Taxes F
Interest, Preferred Dividends and Minority Interest 831; 867; Income Taxes 214 ~546 Income Before Discontinued Oprtin, xraordinary items and Cumulative Effect 21 917 Discontinued Operations - Income (Loss) (net of tax) (190) ~86. Extraordinary Losses (net of tax):.: S Discontinu'ance of Regulatory Accounting for Generation 1 (48): C) Loss on Reacquired Debt:- (2) S C) Cumulative Effect of Accounting Change (net of tax) C) Net Income (Loss) S (~1)I $ 971 -u 0 Average Number of Shares Outstanding.. S M Earnings Per Share: ~.. ..... i3~~: 322 0 0 C,) Income Before Discontinued Opraions, .~~~~~~~~~~~~~~~~~~~~~~~....... C. Extraordinary Items and Cumulative Effect.. 2 85: Discontinued Operationrs. 0:i.26
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Net Income (Loss) I (¶.57r $ 3.01 Z)
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Proceeds from Sale of Retail Electric Providers .~~~~~~~~~~~~~~. Proceeds from Sale of Foreign Investments :
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.':;e n .i-srr To the Shareholders and Board of Directors:: The'management of American Electric Power Company,:.:
of American Electric Power Company, Inc.:-: Inc., is responsible for the integrity, representations and We have audited the consolidated balance sheets of::: objectivity of the information in the Company's sumrmary American Electric Power Company, Inc.,,and its subsidiaries annual report and condensed consolidated financial state-as of December 31, 2002 and 2001, and the related consoli- ments. The condensed consolidated financial statements are dated statements of operations, common shareholders' derived from the consolidated financial statements included
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equity and comprehensive income, and cash flows for each ..in Appendix A to the proxy statement, which has been of the three years in the period ended December 31, 2002. - prepared in conformity with generally accepted accounting These consolidated financial statements and our' report *principles, using informed estimates where appropriate, thereon dated February 21, 2003, expressing an unqualified to reflect the Company's financial condition and results opinion (which are not included herein) are included in.. .::: of operations. The information in other sections of this
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Appendix A to the proxy statement for the 2002 annual summary annual report is consistent with these statements. meeting of.shareholders. The accompanying condensed have been consolidated financial statements .T:::he
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consolidated financial statements are the responsibility audited by Deloitte &Touche LLP, from which these of the Company's management. Our responsibility is to condensed consolidated financial statements have been express an opinion on such condensed consolidated financial derived and whose report appears on this page. The statents in relation to the complete consolidad -. * .> statements in relation to the complete consolidated ;-: S 'auditors provide an objective, independent review as to financial statements. a. management's discharge of its responsibilities insofar as B U In our opinion, the information set forth in the accom-: they relate to the fairness of the Company's reported
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panying condensed consolidated balance sheets as of inancial condition and results of operations. Their audit 7. December 31, 2002 and 2001, and the related condensed : :, :1 includes procedures believed by them to provide reasonable *-u a consolidated statements of operations and of cash flows fort: ,:assurance that the financial statements are free of material::: B
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the years then ended is fairly stated in all material respects misstatement and includes an evaluation of the Company's 0 0 N, in relation to the basic consolidated financial statements-.-'-...:s internal control structure over financial reporting. C from which it has been derived.
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0 Columbus, Ohio Chairman, President & 0. February 21, 2003 Chief Executive Officer .Chief Financial Officer:
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, 7:7 Radian International, LLC.
Austin, Texas (2000) .!N. . -m John P. DesBarres, 63 Investor/Consultante 0 0 Park City, Utah : (997) LH.N.r U, 0. Robert W. Fri 67: Leonard J. Kujawa, 70 Donald G. Smith, 67 Committees of the Board: 0 Visiting Scholar, International Energy Consultant Chairman, President The chairman is listed in (). Resources for the FutureL Atlanta, Georgia:: &Chief Executive Officer, A Audit (Carlton),. M.. Washington, D.C. (1997) D.'- Roanoke Electric Steel Corp. :Directors and Corporate 0 (1995)? Roanoke, Virginia Governance (Hudson),.-.. Dr. Richard L Sandor, 61 (1994) N.?- -: : Executive (Draper), William R. Howell 67 Chairman &Chief Finance (Stunt), Co. Chairman Emeritus, Executive Officer, Linda Gillespie Stuntz, 48 H Human Resources (DesBarres), J.C. Penney Company, Inc. Environmnental Financial. Partner-: N Nuclear Oversight (Sullivan),: Dallas, Texas Products, LLC Stuntz, Davis &Staffier, P.C. Policy (Fri) .0 (2000) .H.P Chcago, Illinois Washington, D.C. (2000)Drf~g (1993) "- ' Dr. Lester A. Hudson, Jr., 63 LU Professor of Business Strategy, Thomas V. Shockley, III, 57 Dr. Kathryn D. Sullivan, 51 Clemson University Vice Chairran: President &Chief 0 Greenville, South Carolina:':: (2000) Executive Officer, (18)A-DJ : : i Center of Science &Industry 0C1 Columbus, Ohio (1997) AN.r
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-I American Electric P'ow ver;0-3 0 Joseph M. Buonaiuto
-Service Corporatior nI::0:; i,0- Senior Vice President, Controller and E. Unn Draper, Jr.: f; -t,; Chief Accounting Officer Chairman, President and Chief Executive Officer . Jeffrey D. Cross
- ::::::: Senior Vice President, Thomas V. Shockley, lli :: -:- -, General Counsel and if -::
- Vice Chairman and-:'H: i; Assistant Secretary.
*:! i: i E Chief Operating Officer i.:
fi -. . :. Joseph Hamrock f i-D:: :S Henry W. Fayne .- . .: Senior Vice President: - Executive Vice President . General Services :: Thomas M. Hagan - -:00-S't.t Dale E. Heydlauff
-Eecutive Vice President - Senior Vice President -
Shared Services -: Governmental and
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Environmental Affairs Holly K. Koeppel Executive Vice President Robert P.Powers Executive Vice President -
' Michelle S. Kalnas Senior Vice President -
Supiply Chain, ' Richard E. Munczinski Generation -117 ,,' i'- Vice Preside'nt -
. ... Senior
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- :. .. : :.. . -:.L:, : . Susan Tomasky .:- : -- Corporate Planning .:- -Office of the Chairmanr American Electri c Power Executive Vice President- and Budgeting:
Front row Iet to right: Holly K. Koeppel, Company. Inc. Pollcy, Fiance and:. t:'T-ttT,i E. Irnn Draper, Jr., Thomas M. Hagan, Strategic Planning, and Armando A. Pe a (l} i :000 'l: Susan Tomasky, Bac row lift to right: E. Linn Draper, Jr. ::Assistant Secretary :gE: : Senior Vice President Robert P. Powers, Henry W. Fayne, Chairman, President and - :: if:: Finance and Treasurer
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Thomas V. Shockley, III Chief Executive Offi Melinda S. Ackerman:? Senior Vice President - ' ;'::" Michael W.: Rencheck . - Thomas V. ShocklhDy,Il Human Resources *....:!g:-t,,- Senior Vice President - Vice Chairman: *:.i-:-. :i: [- Technical Services:: m
......: -S Nicholas J. Ashooh -E. : i Henry W. Fayne ce.
Senior Vice President- t! t :,. William L Sigmon, Jr.:-: Vice President Corporate Communuications s' f' ': Senior Vice President - :: 0 Ef-
.- i Fossil and Hyro H.
Armando A. Pe a J. Craig Baker. 0;$ tiE: 'i',t-;Generation -
.Treasurer Seniomor Vice President - -,.,.-;fX,,,..,404 Regulation and Public Polic icye: :: Scott N. Smith -
Senior Vice President . -. : W Susan Tomasky Vice President, Secnr IA. Christopher Bakken, IIIiiE--T --- and Chief Risk Officer:0 3 and Chief Financial Offic ,,.Senior Vice President .- -' fiSif -ff. -:
- . 03 Nuclear Operations Joseph M. BuonaiiLito. tt';;--i.E.- EE.
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Eif i:: iL Controller and.. i: .:. ..li ..E:E..... iE:EE:iE:: :E Chief Accounting 0 icer
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_,_-:,_1_ Annual Meeting - The 96th annual meeting of shareholders Stock Held in Brokerage Account ('Street Name') - When of American Electric Power Company will be held at 9:30 a-m. you purchase stock and it is held for you by your broker, it is listed Wednesday, April 23, 2003, at The Ohio State University's Fawcett with the Company in the broker's name or 'street name.' AEP Center, 2400 Olentangy River Road, Columbus, Ohio. Admission does not know the identity of idivdual shareholders who hold is by ticket only. To obtain a ticket, please note the instructions in their shares in this manner, we simply know that a broker holds the Notice of Annual Meeting mailed to shareholders or call the a certain number of shares which'may be for any number of Company. If you hold your shares through a broker, please bring customers. If you hold your stock in street name, you receive all proof of share ownership as of the record date. dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any Shareholder Inquiries - If you have questions about your account, questions you may have about your account should be directed contact the Company's transfer agent, listed below. You should have to your broker. your Social Security number or account number ready; the transfer agent will not speak to third parties about an account without the How to Consolidate Accounts - If you want to consolidate your shareholder's approval or appropriate documents. separate accounts into one account, you should contact the transfer agent to obtain the necessary instructions. When accounts are Transfer Agent &Registrar consolidated, it' may be necessary to reissue the stock certificates. EquiServe Trust Company, N.A. ;;..C X.,. ' --A. f:.. .-.-..... ... E i ! : ; A:. :. (formerly First Chicago Trust Company of New York) How to Eliminate Duplicate Mailings - If you want to maintain P.O. Box 43069 more than one account but eliminate additional mailings of annual Providence, RI 02940-3069 reports, you may do so by contacting the transfer agent, indicating Telephone Response Group: 1-800-328-6955 the names you wish to keep on the mailing list for annual reports Internet address: www.equiserve.com and the names you wish to delete. This will affect only these Hearing Impaired #: TDD: 1-800-952-9245 mailings; dividend checks and proxy materials will continue to be sent to each accountI: IdE i-Internet Access to Your Account - If you are a registered shareholder, you can access your account information through Stock Trading - The Company's common stock is traded princi-the Internet at www.equiserve.com. Information about obtaining pally on the New York Stock Exchange under the ticker symbol. a password is available toll-free at 1-877-843-9327. AER AEP stock has been traded on the NYSE for 54 years. Replacement of Dividend Checks - If you do not receive your Taxes on Dividends -The Company paid $2.40 in cash dividends dividend check within five business days after the dividend'pay- in 2002, all of which' are taxable for federal income tax purposes. ment date, or if your check is lost, destroyed or stolen, you should AEP has paid consecutive quarterly dividends since 1910. notify the transfer agent for a replacement. Shareholder Direct - An array of timely recorded messages. Lost or Stolen Stock Certificates - If your stock certificate about AEP, including dividend and earnings information and is lost, destroyed or stolen, you should notify the transfer agent recent news releases, is available from AEP Shareholder Direct immediately so a 'stop transfer' order can be placed on the at 1-800-551-lAEP (1237) anytime day or night. Hard copies of missing certificate. The transfer agent then will send you the information can be obtained via fax or mail. Requests for annual required documents to obtain a replacement certificate. reports, 10-K's, 10-Q's, Proxy Statements and Summary Annual I Reports should be made through Shareholder Direct. Cd, Address Changes - It is important that we have your current address on file so that you do nor become a lost shareholder. Please Financial Community Inquiries - Institutional investors M contact the transfer agent for address changes fbr both record and or secunities analysts who have questions about the Company; dividend mailing addresses. We also can provide automatic should direct inquiries to Bette Jo Rozsa, 614-716-2840, seasonal address changes. bjrozsa@aep.com, orJulie Sloar, 614-716-2885, jsloat@aep.com; E: individual shareholders should contact Kathleen Kozero, : E. Stock Transfer - Please contact the transfer agent if you 614-716-2819, klkozero@aep.com, or April Dawson, have questions regarding the transfer of stock and related 614-716-2591 addawson aep.com. legal requirements,. - Internet Home Page -Information about AEP, including Li) Dividend Rei'nvestment and Direct Stock Purchase Plan - financial documents, SEC filings, news releases and customer A Dividend Reinvestment and Direct Stock Purchase Plan is avail- service information, is available on the Company's home page,:, able to all investors. It is an' economical and convenient method of on the Internet at www..aep.coml. purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the Annual Report and Proxy Materials - You can receivei: transfer agent... i future annual reports, proxy statements and proxies electronically rather than by mail; if you are'a registered holder, log on to Direct Deposit of Dividends - The Company does offer electronic wvww.econsent.comlaep.- If you hold your shares in street name, deposit of your dividends. Contact the transfer agent for details. contact your broker.-7IEI:Ii;
WA MT NO MN i ME OR I0 So VT NH WY M! NY I MA [A NE CT RI NJ NV UT MD co DE CA KS MO OKDr TN NC AZ NM AR C.. SC F:ti'S . MS AL GA C) N-W LA
- AEP service area I-l,
-; Transmission lines FL More than 42,000 megawatts of electric generating 6,400 miles of natural gas pipeline capacity, including the largest generation fleet in the U.S.- 7,000 rail cars 38,000 circuit miles of transmission lines 1,800.barges and 37 tug boats .
186,000 miles of distribution lines:. Annual coal production capability of 10 million tons z iz , -z 128 billion cubic feet of gas storage e American Electric Power owns and operates more than;' West Virginia. The company's distribution service area: 42,000 megawatts of generating capacity in the United *6covers 197,500 square miles.,
.States and select international markets and is the largest electricity generator in the U.S. AEP is also one of the Outside the United States, AEP holds interests in the United largest electric utilities in the United States, with almost 5 Kingdom, Australia, Brazil, China, Mexico and the Pacific million customrers linked to AEP's electricity transmission Regions bs i C Ohio.
and distribution grid. Those customers are located in 11 states - Arkansas, Indiana, Kentucky, Louisiana, Michigan, .AEP is based in Columbus, Ohio. 4 f 0;> Ohio Oklahoma, Tennessee, Texas, Virginia and
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 experience in the wholesale business. or the Company) is one of the largest investor owned electric public utility holding companies Through our utility operations focus, we intend in the U.S. We provide generation, to be the energy and low cost generation transmission and distribution service to almost provider of choice. We have ample five million retail customers in eleven states generation to meet our customers needs. (Arkansas, Indiana, Kentucky, Louisiana, We have a cost advantage resulting from Michigan, Ohio, Oklahoma, Tennessee, AEP s long tradition of designing, building and Texas, Virginia and West Virginia) through operating efficient power plants and delivery our electric utility operating companies. networks. Our customers continue to show top quartile level of satisfaction. We provide We have a vast portfolio of assets including: safe and reliable sources of energy.
- 38,000 megawatts of generating capacity, the largest complement of Our business provides a vital requirement of generation in the U.S., the majority of our economy and affords an opportunity for a which has asignificant cost advantage fair return to our shareholders. Our business in our market areas provides the opportunity for a predictable
. 4,000 megawatts of generating stream of cash flows and earnings, allowing capacity in the U.K., a countrywhich is us to pay a competitive dividend to investors.
currently experiencing excess generation capacity We are addressing many challenges in our
- 38,000 miles of transmission lines, the unregulated business. We have already backbone of the electric substantially reduced our trading activities.
interconnection grid in the Eastern We have written down the value of several U.S. investments to reflect deterioration in market
- 186,000 miles of distribution lines that conditions. We are evaluating our portfolio support delivery of electricity to our and plan to sell assets that are no longer core customers premises to our business strategy. We are also in a Substantial coal transportation assets discussion with our regulators to determine if (7,000 railcars, 1,800 barges, 37 tug the legal separation of certain operating boats and two coal handling terminals company subsidiaries into regulated and with 20 million tons of annual capacity) unregulated segments can be avoided. We
- 6,400 miles of gas pipelines in believe that the expected benefits from legal Louisiana and Texas with 128 Bcf of separation are no longer compelling.
gas storage facilities Transition rules for Michigan and Virginia do not require legal separation. Deregulation is Business Strategy no longer an expectation in the foreseeable future in the other states where we operate. We plan to focus on utility operations in the U.S. We continue to participate in wholesale Our strategy for the core business of utility electricity and natural gas markets. Weakness operations is to: in these markets after the collapse of Enron . Maintain moderate but steady and other companies caused us to re- earnings growth examine and realign our strategy to direct our
- Maximize value of transmission assets attention to our utility markets. We have and protect our revenue stream in an reduced trading to focus predominantly in RTO membership environment markets where we have assets. We plan to
- Continue process improvement to obtain maximum value for our assets by maintain distribution service quality selling excess output and procuring while, at the same time, further economical energy using commercial enhancing financial performance expertise gained from our extensive
- Optimize generation assets through increased availability and sale of A-2
excess capacity We also focused on: Manage the regulatory process to
- Implementing an enterprise-wide risk maximize retention of earnings management system improvement while providing fair and
- Completing a cost reduction initiative reasonable rates to our customers which we expect to result in sustainable net annual savings of We remain very focused on credit quality and more than $200 million beginning in liquidity as discussed in greater detail later in 2003 this report.
- Eliminating or reducing future capital requirements associated with non-We are committed to continually evaluating core assets the need to reallocate resources to areas with greater potential, to match investments with We have redirected our business strategy by:
our strategy and to pare investments that do
- Scaling back trading activities to focus not produce sufficient return and sustainable principally on supporting our core shareholder value. Any investment assets dispositions could affect future results of
- Selling our Texas retail business operations, cash flows and possibly financial . Proposing the sale of a significant condition. portion of the Texas unregulated generation assets 2002 Overview Outlook for 2003 2002 was a year of rapid and dramatic change for the energy industry, including We remain focused on the fundamental AEP, as the wholesale energy market quickly earnings power of our utility operations, and shrank and many of its participants exited or we are committed to strengthening our significantly limited future trading activity. balance sheet. Our strategy for achieving Investors lost confidence in corporate these goals is well planned:
America and the economy stalled. Investors
- First, we will continue to identify demand for stability, predictable cash flows, opportunities to reduce our operations earnings, and financial strength have replaced and maintenance expense.
their demand for rapid growth.
- Second, we will find opportunities to reduce capital expenditures.
Our wholesale business did not perform well. We had significant losses in options trading in
- Third, management recommended a the first half of the year and new investments 40% reduction in the common stock performed well below our expectations. dividend beginning in the second quarter to a quarterly rate of $0.35 per We focused on financial strength by: share. This will result in annual cash
- Issuing approximately $1 billion in savings of approximately $340 million and should improve our retained common stock and equity units earnings as well as create free cash
. Retiring debt of approximately $3 flow to improve liquidity and pay-down billion through the sale of two foreign outstanding debt.
retail utility companies in the U.K. (SEEBOARD) and Australia
- Fourth, we plan to evaluate and, where appropriate, dispose of non-(CitiPower) core assets. Proceeds from these
- Establishing a cash liquidity reserve of sales will be used to reduce debt.
$1 billion at year-end . Fifth, we will continue to evaluate the potential for issuing additional equity See Financing Activity in Managements to further strengthen our balance Discussion and Analysis of Financial sheet and maintain credit quality.
Condition, Accounting Policies and Other Matters in section M for an overview of all We remain committed to being a low cost changes to capital structure. provider of electricity, to serving our A-3
customers with excellence and to providing an wholesale energy markets and in attractive return to investors. We will telecommunications. In 2002, the Company s therefore focus on producing the best Net Loss was $519 million or a loss of $1.57 possible results from our utility operations per share including the fourth quarter losses, enhanced by a commercial group that losses on sales of SEEBOARD and ensures maximum value from our assets. CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and Although we aim for excellent results from CitiPower that resulted from the adoption of operations there are challenges and certain SFAS 142 (see Note 3). risks. We discuss these matters in detail in the Notes to Financial Statements and in Net Income increased in 2001 to $971 million Management s Discussion and Analysis of or $3.01 per share from $267 million or $0.83 Financial Condition, Accounting Policies and per share in 2000. The increase of $704 Other Matters. We will work diligently to million or $2.18 per share was due to the resolve these matters by finding workable growth of AEP s wholesale marketing solutions that balance the interests of our business, increased revenues and the customers, our employees and our investors. controlling of our operating and maintenance costs in the energy delivery business, and Results of Operations declining capital costs. The effect of 2000 charges for a disallowance of COLI-related In 2002, AEP s principal operating business tax deductions, expenses of the merger with segments and their major activities were: CSW, write-offs related to non-regulated
- Wholesale: investments and restart costs of the Cook o Generation of electricity for Nuclear Plant were all contributing factors to sale to retail and wholesale the increase in 2001 earnings compared to customers 2000. The favorable effect on comparative o Gas pipeline and storage Net Income of these 2000 charges was offset services in part in 2001 by losses from Enron s o Marketing and trading of bankruptcy and extraordinary losses for the electricity, gas, coal and other effects of deregulation and a loss on commodities reacquired debt.
o Coal mining, bulk commodity barging operations and other Our wholesale business has been affected by energy supply related a slowing economy. Wholesale energy businesses margins and energy use by industrial Energy Delivery customers declined in 2002 and 2001. o Domestic electricity trans- Earnings from our wholesale business, which mission includes generation, increased in 2001 largely o Domestic electricity distri- as a result of the successful return to service bution of the Cook Plant in June 2000 and by
- Other Investments acquisitions of HPL and MEMCO.
o Energy Services Our energy delivery business, which consists Net Income of domestic electricity transmission and distribution services, contributed to the Income Before Discontinued Operations, increase in earnings by controlling operating Extraordinary Items and Cumulative Effect and maintenance expenses and by increasing decreased $896 million or 98% to $21 million revenues in 2002 and 2001. in 2002 from $917 million in 2001. The Company recognized impairments on under- Capital costs decreased due primarily to performing assets and recorded losses in interest paid to the IRS in 2000 on a COLI value of $854 million (net of tax) (see Note deduction disallowance and continuing 13). The losses in the fourth quarter 2002 declines in short-term market interest rate were generally caused by the extended conditions since early 2001. decline in domestic and international A-4
Volatility in energy commodities markets has had a major effect on the volume of affects the fair values of all of our open wholesale power marketing especially in the trading and derivative contracts exposing AEP short-term market. to market risk and causing our results of operations to be more volatile. See 'Market The increase in 2002 in wholesale revenues Risks section for a discussion of the policies resulted from a 27% increase in trading and procedures AEP uses to manage its volume associated with Wholesale Electricity exposure to market and other risks from which was offset by a continuing decrease in trading activities. gross margins which began in the fourth quarter of 2001, and an increase in Revenues Increase residential sales as a result of favorable weather conditions in the third quarter 2002. AEP s total revenues increased 14% in 2002 In addition OtherWholesale electric revenues and 15% in 2001. The following table shows increased due to the mid-year 2001 the components of revenues: acquisition of barging and coal mining operations as well as the recognition of For The Year Ended revenues for generation projects completed December 31 2002 2001 2000 for third parties. The increase in 2002 (in millions) WHOLESALE: Wholesale Gas revenues resulted from a full Residential commercial
$ 3,713 2,156 S 3,553 S 3,511 2,328 2,249 year of HPL operations compared to a partial Industrial 1,903 2,388 2,444 year from our acquisition date in July 2001, other Retail offset by a decrease in the results from customers 385 419 414 financial trading and MTM unrealized losses.
Electricity Marketing (net) 2,227 802 1,073 Other Investments revenue decreased in unrealized MTM 2002 due to the elimination of factoring of Income-Electric 136 210 38 other 1,397 632 837 accounts receivable of an unaffiliated utility. Less: Transmission and Distribution Revenues Assigned to Energy Prior to the third quarter of 2002, we recorded Delivery* (3.551) i (3.356) (3.174) and reported upon settlement, sales under wholesale Electric 8.366 6,97 7,392 forward trading contracts as revenues and Gas Marketing (net) 3,021 2,274 310 purchases under forward trading contracts as unrealized MTM Income purchased energy expenses. Effective July 1, (Loss)-Gas (399) 47 132 wholesale Gas 2.622 2.321 442 2002, we reclassified such forward trading TOTAL WHOLESALE 10.988 9.297 7,834 revenues and purchases on a net basis, as DOMESTIC ELECTRICITY permitted by EITF 98-10 (see Note 1). DELIVERY: Transmi ssi on 922 1,029 1,009 Distribution 2.629 2,327 2.165 Kilowatthour sales to industrial customers TOTAL DOMESTIC decreased by 10% in 2002 and by 5% in ELECTRICITY 2001. This decrease was due to the DELIVERY 3.551 3,356 3,174 economic slow down which began in late OTHER INVESTMENTS 16 114 105 2001. Sales to residential customers rose 5% due to weather related demand in 2002. The TOTAL REVENUES S14,5m 11.77
, economic slow down reduced demand and
- Certain revenues in the wholesale business wholesale prices especially in the latter part of include energy delivery revenues due primarily to bundled tariffs that are assignable to the 2001.
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 CSW, certain deferred merger costs were expensed in 2000. The merger costs charged Changes in the components of operating to expense included transaction and transition expenses were as follows: costs not allocable to and recoverable from ratepayers under regulatory commission Inc:rease (Decrease) approved settlement agreements to share net Frtom Previous Year 2002 200. merger savings. As expected, merger costs (in millions) Amourit % Amount % declined in 2001 and 2002 after the merger Fuel and Purchased was consummated. Energy: Electricity $ 959 43.7 S(1,275)(36.7) Gas 404 14.7 2,339 570.5 In 2002 AEP recorded pre-tax impairments of Maintenance and other operation 303 8.2 228 6.5 assets (including Goodwill) and investments Non-recoverable totaling $1.4 billion (consisting of Merger Costs (11) i (52.4) (182) (89.7) Asset Impairments 867 N.M. approximately, $866.6 million related to asset Depreciation and Amortization 134 10.8 152 13.9 impairments, $321.1 million related to Taxes other Than investment value losses, and $238.7 million Income Taxes 51 7.6 (16) (2.3) Total 25.6 51.246 13.3 related to discontinued operations) that reflected downturns in energy trading The increase in Fuel and Purchased Energy markets, projected long-term decreases in expense was primarily attributable to an electricity prices, and other factors. These increase in power generation. Net generation impairments exclude the transitional increased 6% for Eastern plants due to impairment loss from adoption of SFAS142 increased demand for electricity and a (see Note 2). The categories of impairments reduction in planned power plant maintenance included: outages for various plants as compared to 2001. The return to service of the Cook 2002 Pre-Tax Estimated Loss (in millions) Plants two nuclear generating units in June 2000 and December 2000 accounted for the Asset Impairments increase in nuclear generation. The increase Held for sale S 483.1 Asset Impairments in Gas expense was primarily due to a full Held and used 651.4 year of HPL operations compared to a partial Investment value Losses 291.9 year from our acquisition date in July 2001. Total The increase in Maintenance and Other Operation expense in 2002 is primarily due to Additional market deterioration associated recognizing a full years expense for the with our non-core wholesale investments, businesses acquired during 2001 including including our U.K. operations, could have an MEMCO (a barging line), Quaker Coal, two adverse impact on our future results of power plants in the U.K. and HPL. In addition, operations and cash flows. Significant long-increased administrative costs for the term changes in external market conditions implementation of customer choice in Texas could lead to additional write-offs and contributed to the increase. The increase was potential divestitures of our wholesale offset in part by a reduction in trading investments, including, but not limited to, our incentive compensation and the effect of U.K. operations. planned boiler plant maintenance at various plants in 2001 and less refueling outages for The rise in Depreciation and Amortization STP in 2002 than 2001. expense in 2002 resulted from the amortization of Texas generation related Maintenance and Other Operation expense Regulatory Assets that were securitized in rose in 2001 mainly as a result of additional early 2002, businesses acquired in 2001 and traders incentive compensation and accruals additional production plant placed into for severance costs related to corporate service. restructuring. Depreciation and Amortization expense With the consummation of the merger with increased in 2001 primarily as a result of the A-6
commencement of amortization of transition This increase was primarily caused by an generation regulatory assets in the Ohio, increase in equity earnings due to acquisitions Virginia and WestVirginia jurisdictions due to of $63 million and a $73 million gain from the passage of restructuring legislation, the new sale of a generating plant (see Note 1). Other businesses acquired in 2001 and additional Expenses increased by $110 million or 143% investments in Property, Plant and in 2001 due to costs to exit air transportation, Equipment. fiber optic and Datapult businesses (see Note 1). Taxes OtherThan IncomeTaxes increased in 2002 due to a full year of state excise taxes Income Taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in The decrease in total Income Taxes in 2002 Texas partly offset by the effect of Texas one- was due to a decrease in pre-tax book income time 2001 assessments and decreased gross offset by the tax effects of the sale of foreign Texas receipts taxes due to deregulation. operations. Interest. Preferred Stock Dividends, Minority Although pre-tax book income increased Interest considerably in 2001, Income Taxes decreased due to the effect of recording in The decrease in Interest in 2002 was primarily 2000 prior year federal income taxes as a due to a reduction in short-term interest rates result of the disallowance of COLI interest and lower outstanding balances of short-term deductions by the IRS and nondeductible debt and the refinancing of long-term debt at merger related costs in 2000. favorable interest rates offset in part by an increased amount of long-term debt Extraordinary Losses and Cumulative Effect outstanding. The loss for transitional goodwill impairment Interest expense decreased 15% in 2001 due related to SEEBOARD and CitiPower resulted to the effect of interest paid to the IRS on a from the adoption of SFAS 142 (see Notes 2 COLI deduction disallowance in 2000 and and 3) and has been reported as a lower average outstanding short-term debt Cumulative Effect of Accounting Change on balances and a decrease in average short- January 1, 2002. term interest rates. In 2001 we recorded an extraordinary loss of Minority Interest in Finance Subsidiary $48 million net of tax to write-off prepaid Ohio increased substantially in 2002 because the excise taxes stranded by Ohio deregulation. distributions to minority interest were in effect The application of regulatory accounting for for the entire year. In 2001 we issued a generation was discontinued in 2000 for the preferred member interest to finance the Ohio, Virginia and West Virginia jurisdictions acquisition of HPL and paid a preferred return which resulted in the after-tax extraordinary of $13 million to the preferred member loss of $35 million. interest. The minority interest was only in effect during the last four months of 2001. New accounting rules that became effective in 2001 regarding accounting for derivatives Other Income/Other Expenses required us to mark-to-market certain fuel supply contracts that qualify as financial Other Income increased by $110 million or derivatives. The effect of initially adopting the 33% in 2002 due to the sale of AEP S retail new rules at July 1, 2001 was a favorable electric providers in Texas and due to non- earnings effect of $18 million, net of tax, operational revenue (see Note 1). Other which is reported as a Cumulative Effect of Expenses increased $134 million or 72% in Accounting Change. 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) L3.01 $ 0.83 I$(1.5) 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) Accumulated other Common stock Paid-In Retained comprehensive shares Amount Capi tal Earnings Income (Loss) Total DECEMBER 31, 1999 331 $2,149 $2,898 S3,630 $ (4) $8,673 Issuances - 3 11 14 cash Dividends Declared (805) (805) Other 6 (2) 4 7,886 comprehensive Income: Other Comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment (119) (119) Reclassification Adjustment For LOSS Included in Net Income 20 20 Net Income 267 267 Total Comprehensive Income 168 DECEMBER 31, 2000 331 $2,152 S2,915 $3,090 S(103) $8,054 Issuances 1 9 10 cash Dividends Declared (773) (773) other (18) 8 (10) 7,281 comprehensive Income: Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment (14) (14) unrealized Gain (Loss) on Hedged Derivatives (3) (3) Minimum Pension Liability (6) (6) Net Income 971 971 Total Comprehensive Income 948 DECEMBER 31, 2001 331 $2,153 S2,906 $3,296 S(126) $8,229 Issuances 17 108 568 676 cash Dividends Declared (793) (793) Other (61) 15 (4 ) (163) Com prehensive Income: Other comprehensive Incomes Net of Taxes Foreign Currency Translation Adjustment 117 117 unrealized Gain (Loss) on Hedged Derivatives (13) (13) Minimum Pension Liability (585) (585) unrealized Loss on securities Available For Sale (2) (2) Net Income (Loss) (519) (519) Total comprehensive Income (1.002) DECEMBER 31, 2002 MA S3.13 1S9M sff) 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 weighted Average Maturity Interest Rate Interest Rates at December 31. December 31. December 31. 2002 2002 2001 2002 2001 (in millions) FIRST MORTGAGE BONDS (a) 2002 -2004 6.87% 6.00%-7.85% 6.00%-7.85% $ 648 S 1,246 2005 -2008 6.90% 6.20%-8% 6.20%-8% 463 699 2022-2025 7.66% 6.875%-8.7% 6-7/8%-8.80% 773 850 INSTALLMENT PURCHASE CONTRACTS (b) 2002-2009 4.62% 3.75%-7.70% 1.80%-7.70% 396 446 2011-2030 5.83% 1.35%-8.20% 1.55%-8.20% 1,284 1,234 NOTES PAYABLE (c) 2002-2021 5.54% 3.732%-9.60% 4.048%-9.60% 520 217 SENIOR UNSECURED NOTES 2002 -2005 5.53% 2.12%-7.45% 2.31%-7.45% 1,834 1,910 2006-2012 5.91% 4.31%-6.91% 6.125%-6.91% 2,295 1,727 2032-2038 6.64% 6.00%-7-3/8% 7.20%-7-3/8% 690 340 JUNIOR DEBENTURES 2025-2038 7.90% 7.60%-8.72% 7.60%-8.72% 205 618 SECURITIZATION BONDS 2003-2016 5.40% 3.54%-6.25% 797 OTHER LONG-TERM DEBT (d) 247 258 Unamortized Discount (net) (32) (40) Total Long-term Debt outstanding 10.120 9, 505 Less Portion Due Within One Year 1 633 1.095 Long-term Portion L 8410 EQUITY UNIT SENIOR NOTES 2007 5.75% 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 S 1,633 2004 824 2005 993 2006 1,611 2007 1,081 Later Years 4.386 10,528 Unamortized Discount 32 Total £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. combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 Goodwill and other Intangible Assets Note 3 Merger Note 4 Nuclear Plant Restart Note 5 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 Impairments and Investment value Losses Note 13 Benefit Plans Note 14 stock-Based compensation Note 15 Business Segments Note 16 Risk Management, Financial Instruments And Derivatives Note 17 Income Taxes Note 18 Basic and Diluted Earnings Per share Note 19 Supplementary Information Note 20 Power and Distribution Projects Note 21 Leases Note 22 Lines of credit and sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Minority Interest in Finance subsidiary Note 26 Equity units Note 27 Subsequent Events (unaudited) 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 inthe 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 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $213,281 $227,548 $228,516 $217,189 $224,146 operating Expenses 207,152 220.571 220,092 211,849 215,415 operating Income 6,129 6,977 8,424 5,340 8,731 Nonoperating Items, Net 3,681 3,484 3,429 3,659 3,364 Interest charges 2,258 2,586 3.869 2.804 3.149 Net Income ,$L52 $ 77875 $ ,94 $6J195 $ Ai December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $652,213 $648,254 $642,302 $640,093 $636,460 Accumulated Depreciation 358.174 337,151 315.566 295.065 277. 855 Net Electric Utility Plant $-3-1-,10 $36,736 ,$345,028 Total Assets $349,729 $361,41 $374,602 A
$403 U892 Common stock and Paid-in capital $ 24,434 $ 24,434 $ 24,434 $ 30,235 $ 36,235 Retained Earnings 18.163 13.76 9,722 3.673 2,770 Total Common shareholder's Equity $ 4259 $ 3-8,19-5 $900 Long-term Debt (a) S_4i8QZ $4,793 $ 44,808 $ 48 44,79 Total Capitalization And Liabilities UAJTZ9 $36 1 ,41 $374,602 $98 4 $4031892 (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 Operating Expenses Decrease generation and wholesale sale of electric power to two affiliates under long-term Operating Expenses decreased 6% as agreements. follows: Increase Operating Revenues are derived from the (Decrease) (dollars in thousands) From Previous Year sale of Rockport Plant energy and capacity to . _ _ . . _ . _ . ., _ _ _ _ _ _ _ _ _ Amount % two affiliated companies, I&M and KPCo, Fuel $(13,723) (13) pursuant to FERC approved long-term unit other operation 1,899 17 power agreements. Under the terms of its Maintenance 565 6 Depreciation 137 1 unit power agreement, l&M will purchase all of Taxes other Than Income AEGCo's Rockport capacity unless it is sold to Taxes (976) (23) Income Taxes (1.321) (46) other utilities. A unit power agreement Total S(3,41) (6) between AEGCo and KPCo expires in 2004. The KPCo unit power agreement extends until The decrease in Fuel expense reflects a December 31, 2009 for Rockport Plant Unit 1 decrease in generation and lower average and until December 7, 2022 for Rockport fuel costs. Plant Unit 2 if AEP s restructuring settlement agreement filed with the FERC becomes operative. The unit power agreements Other Operation expense increased due to increased costs for employee benefits and provide for recovery of costs including a property insurance. FERC approved rate of return on common equity and a return on other capital net of The increase in Maintenance expense can be temporary cash investments. Under terms of attributed to shorter duration of maintenance the unit power agreements, AEGCo outages for boiler inspection and repair in accumulates all expenses monthly and 2001. prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and establishes a receivable from the affiliated personal property taxes reflecting a favorable companies. change in the law which lowered the tax for Rockport Plant. Results of Operations The decrease in Income Taxes attributable to Net Income decreased $323,000 or 4% as a operations is primarily due to a decrease in result of limits on recovery of return on capital pre-tax operating income and a change in related to operating and in-service ratios of estimate for state income tax accruals. the Rockport Plant. 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 Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING REVENUES $213.281 $227.548 $228,516 OPERATING EXPENSES: Fuel 89,105 102,828 102,978 Rent - Rockport Plant Unit 2 68,283 68,283 68,283 other operation 12,924 11,025 10,295 Maintenance 9,418 8,853 9,616 Depreciation 22,560 22,423 22,162 Taxes other Than Income Taxes 3,281 4,257 3,854 Income Taxes 1.581 2.902 2.904 TOTAL OPERATING EXPENSES 207,152 220. 571 220.092 OPERATING INCOME 6,129 6,977 8,424 NONOPERATING INCOME 343 30 6 NONOPERATING EXPENSES 198 16 17 NONOPERATING INCOME TAX CREDITS 3,536 3,470 3,440 INTEREST CHARGES 2.258 2.586 3.869 NET INCOME .$ -752 $_zl875 $ 7L984 Statements of Retained Earnings Year Ended December 31. 2002 2001 2000 (in thousands) RETAINED EARNINGS JANUARY 1 $13,761 $ 9,722 $3,673 NET INCOME 7,552 7,875 7,984 CASH DIVIDENDS DECLARED 3 150 3.836 1.935 RETAINED EARNINGS DECEMBER 31 18&-63 $13 ,761 $4X7 See Notes to Financia7 Statements beginning on page L-1. 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 S3A4 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 $ 7,552 S 7,875 $ 7,984 Adjustments for Noncash Items: Depreciation 22,560 22,423 22,162 Deferred Income Taxes (5,028) (6,224) (5,842) Deferred Investment Tax Credits (3,361) (3,414) (3,396) Amortization of Deferred Gain on sale and Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571) Change in Certain Current Assets and Liabilities: Accounts Receivable 4,037 1,224 1,392 Fuel, Materials and supplies (5,450) (4,738) 6,486 Accounts Payable 6,697 (4,597) (13,157) Taxes Accrued (2,450) (216) 708 other Assets (5,211) (569) 1,636 other Liabilities (2.295) (1.244) (404) Net Cash Flows From operating Activities 11,480 4,949 11. 998 INVESTING ACTIVITIES Construction Expenditures (5,298) (6,868) (5,190) FINANCING ACTIVITIES: Return of Capital to Parent Company (5,801) change in short-term Debt (net) (24,700) Change in Advances From Affiliates (net) (4,01-5) 3,981 28,068 Dividends Paid (3,150) (3.836) (1.935) Net Cash Flows From (Used For) Financing Activities (7.165) 145 (4,368) Net Increase (Decrease) in cash and cash Equivalents (983) (1,774) 2,440 Cash and cash Equivalents January 1 983 2,757 317 cash and cash Equivalents December 31 $~ _ $ 98 supplemental Disclosure: Cash Paid for interest net of capitalized amounts was $2,019,000, $1,509,000 and $3,531,000 and for income taxes was $7,884,000, $8,597,000 and $6,820,000 in 2002, 2001 and 2000, respectively. 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. combined Footnote Reference significant Accounting Policies Note 1 Effects of Regulation Note 7 Commitments and Contingencies Note 9 Guarantees Note 10 sustained Earnings Improvement Initiative Note 11 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 Related Party Transactions 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 SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $1,690,493 $1,738,837 $1,770,402 $1,482,475 $1,406,117 Operating Expenses 1.296.760 1,443.106 1.463.304 1.188.490 1 123.330 Operating Income 393,733 295,731 307,098 293,985 282, 787 Nonoperating Items, Net 8,079 5,324 7,235 8,113 760 Interest charges 125.871 116.268 124,766 114 380 122.036 Income Before Extraordinary Item 275,941 184,787 189,567 187,718 161,511 Extraordinary Loss (2.509) (5 517) Net Income 275,941 182,278 189,567 182,201 161,511 Preferred stock Dividend Requirements 241 242 241 6,931 6,901 Gain (Loss) on Reacquired Preferred Stock 4 (2.763) Earnings Applicable To Common stock $_275704 1$_182L 06 $ 172.507 L$_ 15-461Q Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,625,736 $5,769,707 $5,592,444 $5,511,894 $5,336,191 Accumulated Depreciation And Amortization 2.405.492 2.446.027 2.297,189 2.247,225 2.072.686 Net Electric Utility Plant $320 -244 Total Assets $5'536P438 $4,735,_ff Common stock and Paid-in capital $ 187,898 $ 573,903 $ 573,904 $ 573,904 $ 573,904 Accumulated other comprehensive Income (Loss) (73,160) Retained Earnings 986.396 826,197 792,219 758.894 734. 387 Total Common shareholder's Equity
$1- 1O1t 13A $1,420QlQQ -$-I33-,79
$1 1QWLZX Preferred stock $ 5,942- $ 5,951 $5.95 CPL Obli ated, Mandatori 1y Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior subordinated Debentures of CPL
$-13-6 Z5- SI136 25Q $148,500 Long-term Debt (a) $1,454,559 $154,5I41 Total capitalization And Liabilities $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 implementation of REPs as suppliers to retail known as Central Power and Light Company customers has caused a significant shift in (CPL), is a public utility engaged in the TCC s sales as described below under generation, purchase, sale, transmission and "Results of Operations. distribution of electric power in southern Texas. TCC also sells electric power at In December 2002, AEP sold the affiliated wholesale to other utilities, municipalities, REP to an unrelated third party who assumed rural electric cooperatives and beginning in the obligations of the affiliated REP under the 2002 to its affiliated retail electric provider Texas Restructuring Legislation (see Note (REP) in Texas. 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Wholesale power marketing activities are Affiliates. Subsequent to the sale, conducted on TCC s behalf byAEPSC. TCC, transactions with the REP were classified as along with the other AEP electric operating Wholesale Electricity or Energy Delivery. subsidiaries, shares in AEP s electric power transactions with other utility systems and Results of Operations power marketers. In 2002, Net Income increased $94 million or 51 % primarily due to $262 million of revenues On January 1, 2002, customer choice of associated with recognition of stranded costs electricity supplier began in the Electric in Texas offset in part by losses associated Reliability Council of Texas (ERCOT) area of with the commencement of customer choice Texas where TCC operates. in Texas which resulted in the loss of customers and reduced prices (see Note 8). Under the Texas Restructuring Legislation, In 2001, Income Before Extraordinary Item each electric utility was required to submit a decreased $5 million or 3%, primarily resulting plan to structurally unbundle its business into from a settlement of Texas municipal an affiliated REP, a power generator, and a franchise fees and increased Maintenance transmission and distribution utility. During expenses. the year 2000, TCC submitted a plan for separation that was subsequently approved Changes in Operating Revenues by the PUCT. TCC has functionally separated its generation from its transmission and Increase (Decrease) From Previ ous Year distribution operations and AEP formed a (dollars in millions) separate affiliated REP. Pending regulatory 2002 2001 Amount % Amount approval, TCC anticipates legally separating whol esal e its generation from its transmission and El ectri ci ty* S(1, 096.4) (90) S(29.9) (2) distribution operations (see Note 8). The Energy Delivery* 81.4 17 (5.6) (1) affiliated REP, aseparate legal entitythatwas Sales to AEP an AEP subsidiary (not owned by or Affiliates 966.7 N.M. 4.0 11 Total 5(8.) (3) 5 31. 5) (2) consolidated with TCC) was sold in December 2002 (see Note 12). *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy Since the affiliated REP is the electricity delivery. supplier to retail customers in the ERCOT N.M. = Not Meaningful area, TCC sells its generation to the affiliated REP and other market participants and In 2002, Wholesale Electricity revenues provides transmission and distribution decreased as a result of the elimination of services to retail customers of the REPs inthe TCCs retail electricity sales in the ERCOT TCC service territory. As a result of the region as of January 1,2002 and a decrease formation of the affiliated REP, effective in wholesale power marketing margins offset January 1, 2002, TCC no longer supplies in part by the interchange cost reconstruction electricity directly to retail customers. The C-2
(ICR) adjustments (see Note 6). In 2001, the based on the current spot market price. decrease in Wholesale Electricity revenues Changes in natural gas prices affect TCC s was primarily attributable to unfavorable fuel expense; however, they generally did not wholesale power marketing and trading impact results of operations in 2001 and 2000 conditions. due to fuel recovery mechanisms, which are no longer in place beginning with deregulation In 2002, Sales to AEP Affiliates revenue in 2002. increased primarily due to increased revenues from the newly created affiliated REP. In 2002, the increase in Wholesale Electricity Although TCC sold electricity to the affiliated Purchased Power expense is due to higher REP instead of directly to retail customers, MWH purchases from the market where we total revenues decreased due to lower prices could purchase power at prices lowerthan our cost to produce. ICR adjustments also had for power sold to the affiliated REP. the effect of increasing Wholesale Electricity Purchased Power expense and decreasing Additionally, delivery charges provided to the AEP Affiliates Purchased Power expense in affiliated REP in 2002 are classified as Sales 2002 (see Note 6). to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery In 2001, Purchased Power increased overall revenue. Revenues for 2002 included $262 largely due to higher natural gas prices. million of revenues, associated with Although gas prices declined in 2001, they recognition of stranded costs in Texas (see were higher during the first half of 2001 when Note 8). Energy Delivery revenue also TCC was making most of its purchases. included revenues received for securitized assets beginning in 2002 (see Note 8). In2002, Other Operation expense decreased due primarily to the elimination of factoring of Chances in Operatinc ExDenses accounts receivable and lower ERCOT Increase (Decrease) transmission related expenses. From Previous Year (dollars in millions) In 2002, Maintenance expense decreased 2002 2001 due to two scheduled '18 month interval Amount % Amount % refueling outages for STP during 2001 that increased Maintenance expense above the Fuel V(:246.2) (50) SC58.8) C11) 2002 and 2000 levels. Also contributing to Purchased Power: the decrease in 2002, and the increase in wholesale Electricity 83.5 65 C16.2) (11) 2001, was an increase in Maintenance AEP 83.5* 65 (16.2) (l ) expense for scheduled major overhauls of Affiliates (35.3) (60) 26.0 80 four power plants in 2001. other operation (17.1) (5) 1-1 1.7
- I -
1 Maintenance tO'.i.) L.+/-+/-J +/-U. I IO In 2002, the increase in Depreciation and Depreci ati on And Amortization is attributable to the amortization Amortization 45.8 27 (10.4) (6) of regulatory assets that were securitized in Taxes other Than Income Taxes 4.6 5 14.4 19 the first quarter of 2002, offset by the Income Taxes 26.1 23 12.4 12 elimination of excess earnings expense in Total la .46) (10) -A) C') 2002 under Texas Restructuring Legislation (see Note 8). In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of In 2002, the increase in Taxes Other Than fuel and decreased generation. The Income Taxes resulted primarily from higher decrease in Fuel expense in 2001 was local franchise taxes, offset by one-time 2001 primarily due to a reduction in the average assessments and decreased gross receipts cost of fuel primarily from a decline in natural tax, due to deregulation. In 2001, Taxes gas prices. TCC used natural gas as fuel for Other Than Income Taxes increased due 32% of its generation in 2002. The nature of primarily to an increase in franchise related the natural gas market is such that both long- taxes, including a settlement of disputed term and short-term contracts are generally franchise fees, and a new tax levied by the C-3
PUCT, the Texas System Benefit Fund current cost to generate electricity, TCC Assessment. proposed in September 2002 to "inactivate various, high-cost gas fired generating In 2002, the increase in Income Taxes is due facilities. In the third quarter 2002, TCC to an increase in pre-tax income offset by recorded an impairment charge of changes in timing between book/tax approximately $95.6 million (pre-tax) related accounting differences in state income taxes. to these plants and recorded approximately In 2001 the increase in Income Tax expense $4.0 million (pre-tax) for severance charges. is primarily due to adjustments associated Both of these charges were deferred and with prior year tax returns and an increase in recorded in RegulatoryAssets Designated for pre-tax book income. or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up Other Changes proceeding (see Note 8). Inthe fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional In 2002, Nonoperating Income and plant impairments, fuel inventory and Nonoperating Expenses increased materials and supplies, and an additional $1.5 significantly as a result of increased non-utility million pre-tax charge was recorded related to revenue and expenses associated with severance charges (see Note 13) related to energy related construction projects for third the Inactivated plants. The entire $23.1 parties, offset in part by decreased interest million was also deferred and recorded in income. The revenues associated with the Regulatory Assets Designated for or Subject energy related construction projects included to Securitization. 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. 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). In2001, 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 $ 127,502 $1,223,893 $1,253,836 Energy Delivery 554,547 473,182 478,814 Sales to AEP Affiliates 1.008.444 41.762 37.752 TOTAL OPERATING REVENUES 1.690.493 1. 738. 837 1.770.402 OPERATING EXPENSES: Fuel 245,834 492,057 550,903 Purchased Power: wholesale Electricity 211,358 127,816 144,021 AEP Affiliates 23,406 58,641 32,591 other operation 304,094 321,227 319,539 Maintenance 63,392 71,212 60,528 Depreciation and Amortization 214,162 168,341 178,786 Taxes other Than Income Taxes 95,500 90,916 76,477 Income Taxes 139.014 112.896 100.459 TOTAL OPERATING EXPENSES 1. 296, 760 1.443.106 1.463. 304 OPERATING INCOME 393,733 295,731 307,098 NONOPERATING INCOME 53,141 22,552 5,830 NONOPERATING EXPENSES 41,910 17,626 3,668 NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,152 (398) (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) (2.509) NET INCOME 275,941 182,278 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS 241 242 241 GAIN ON REACQUIRED PREFERRED STOCK 4 EARNINGS APPLICABLE TO COMMON STOCK $ -18Z-16 Consolidated Statements of Comprehensive Income Year Ended December 31. 2002 2001 2000 (in thousands) NET INCOME $275,941 $182,278 $189,567 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (36) Minimum Pension Liability (73,124) COMPREHENSIVE INCOME $182-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 $ 266197 $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 $2,903,942 $3,169,421 Transmission 698,964 663,655 Distribution 1,296,731 1,279,037 General 258,386 241,137 Construction work in Progress 200,947 169,075 Nuclear Fuel 266.766 Total Electric Utility Plant 5,625,736 5,769,707 Accumulated Depreciation and Amortization 2.405.492 2.446,027 NET ELECTRIC UTILITY PLANT 3.220.244 3. 323.680 OTHER PROPERTY AND INVESTMENTS 3.977 47,950 SECURITIZED TRANSITION ASSETS 734. 591 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4.392 28 039 CURRENT ASSETS: Cash and Cash Equivalents 85,420 10,909 Accounts Receivable: General 113,543 38,459 Affiliated companies 121,324 6,249 Allowance for uncollectible Accounts (346) (186) Fuel Inventory 32,563 38,690 Materials and supplies 51,593 55,475 Accrued Utility Revenues 27,150 Energy Trading and Derivative Contracts 22,493 34,480 Prepayments and other current Assets 2.133 2.742 TOTAL CURRENT ASSETS 455.873 186 818 REGULATORY ASSETS 458. 552 226. 812 REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 336.444 959,294 NUCLEAR DECOMMISSIONING TRUST FUND 98.474 98.600 DEFERRED CHARGES 43,891 21.837 TOTAL ASSETS Sig56E438 $4,9303 See Notes to Financial Statements beginning on page L-1. 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 $ 55,292 $ 168,888 Paid-in Capital 132,606 405,015 Accumulated other comprehensive Income (Loss) (73,160) Retained Earnings 986 396 826.197 Total Common shareholder s Equity 1,101,134 1,400,100 Preferred stock 5,942 5,952 CPL obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding solely Junior subordinated Debentures of CPL 136,250 136,250 Long-term Debt 1,209.434 988.768 TOTAL CAPITALIZATION 2.452.760 2,531.070 OTHER NONCURRENT LIABILITIES 74.572 10.905 CURRENT LIABILITIES: short-term Debt Affiliates 650,000 Long-term Debt Due within one Year 229,131 265,000 Advances from Affiliates (net) 126,711 354,277 Accounts Payable General 72,199 65,307 Accounts Payable Affiliated Companies 36,242 49,301 customer Deposits 666 26,744 Taxes Accrued 24,791 83,512 Interest Accrued 51,205 23,715 Energy Trading and Derivative Contracts 19,811 40,987 other 36. 698 18,076 TOTAL CURRENT LIABILITIES 1.247.454 926.919 DEFERRED INCOME TAXES 1.261.252 1,163.795 DEFERRED INVESTMENT TAX CREDITS 117.686 122.892 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,713 17,675 REGULATORY LIABILITIES AND DEFERRED CREDITS 201.001 119.774 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES S5,356A438 $41 9,83A3D See Notes to Financia7 statements beginning on page L-1. C-8
- - l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31.
2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $275,941 $182,278 $189,567 Adjustments to Reconcile Net Income to Net cash Flows from Operating Activities: Depreciation and Amortization 214,162 168,341 178,786 Extraordinary Loss on Reacquired Debt 2,509 Deferred Income Taxes 113,655 (72,568) 16,263 Deferred Investment Tax credits (5,206) (5,208) (5,207) Mark-toMarket Energy Trading and Derivative Contracts (1,558) (12,048) 8,191 change in Certain Current Assets and Liabilities: Accounts Receivable (net) (189,999) 52,862 (32,902) Fuel, Materials and supplies (4,899) (18,215) 8,680 Interest Accrued 27,490 (2,502) 11,494 Accrued Utility Revenues (27,150) Accounts Payable (6,167) (55, 311) 45,873 Taxes Accrued (58,721) 27,986 14,405 Fuel Recovery 16,455 179,866 (96,872) Transmission coordination Agreement settlement 15,519 Texas wholesale Clawback (see Note 7) (262,000) change in other Assets (534) 10,767 589 Change in other Liabilities 56.024 11,163 12 .243 Net cash Flows From Operating Activities 147.493 469,920 366,629 INVESTING ACTIVITIES: Construction Expenditures (151,645) (193,732) (199,484) Proceeds From Sales of Property and other 143 (354) Net cash Flows used For Investing Activities (151. 502) (194.086) (199.484) FINANCING ACTIVITIES: Issuance of Long-term Debt 797,335 260,162 149,248 change in short-term Debt Affiliate (Net) 650,000 Retirement of Common stock (386,005) Retirement of Preferred stock (6) Retirement of Long-term Debt (639,492) (475,606) (151,440) change in Advances from Affiliates (net) (227,566) 84,565 (52,446) special Deposit for Reacquisition of Long-term Debt 50,000 Dividends Paid on Common stock (115, 505) (148,057) (156,000) Dividends Paid on Cumulative Preferred Stock (241) (242) (249) Net cash Flows From (used For) Financing Activities 78.520 (279,178) (160.887) Net Increase (Decrease) in Cash and Cash Equivalents 74,511 (3,344) 6,258 Cash and Cash Equivalents January 1 10.8909 14.253 7.995 Cash and cash Equivalents December 31 SLQ 3Q9 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) COMMON SHAREHOLDER S EQUITY (a) S1.10o.134 S1.400.100 PREFERRED STOCK 3,035,000 authorized shares, 5100 par value Not Subject to Mandatory Redemption: call Price - Shares December 31, Number of shares Redeemed outstanding series 2002 Year Ended December 31. Dec:ember 31. 2002 2002 2001 2000 4.00% S105.75 100 - - 41,938 4,194 4,204 4.20% 103.75 - - - 17,476 1.748 1,748 Total Preferred stock 5.942 5.952 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 136.250 136. 2 50 LONG-TERM (See schedule of Long-term Debt): First Mortgage Bonds 152,353 614,200 Securitization Bonds (a) 796,635 Installment Purchase Contracts 489, 577 489,568 Senior unsecured Notes - 150,000 Less Portion Due within One year (229.131) (265.000) Long-term Debt Excluding Portion Due within one Year 1.209.434 988. 768 TOTAL CAPITALIZATION (a) In February 2002, TCC issued securitization bonds. S386 million of the proceeds was used to retire 4,543,857 shares of common stock. See Notes to Financial Statements beginning on page L-1. C-1 0
i - AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as December 31, follows: 2002 2001 December 31. (in thousands) 2002 2001 % Rate Due (in thousands) Matagorda County
% Rate Due Navigation District, 7.25 2004 October 1 S 27,400 $100,000 Texas:
7.50 2002 December 1 115,000 6.00 2028 July 1 $120,265 S120,265 6-7/8 2003 February 1 16,418 49,200 6-1/8 2030 May 1 60,000 60,000 7-1/8 2008 February 1 18,581 75,000 3.75 2030(a) May 1 111,700 111,700 7.50 2023 April 1 17,996 75,000 4.00 2030(a) May 1 50,000 50,000 6-5/8 2005 July 1 71. 958 200 000 4.55 2029(a) Nov . 100,635 100,635 Total ikQu Q Guadalupe-Blanco River Authority First mortgage bonds are secured by a first District, Texas: mortgage lien on electric utility plant. The (b) 2015 November 1 40,890 40,890 indenture, as supplemented, relating to the Red River Authority first mortgage bonds contains maintenance District, Texas: 6.00 2020 June 1 6,330 6,330 and replacement provisions requiring the unamortized Discount (243) (252) deposit of cash or bonds with the trustee, or in Total S4O9,577 lieu thereof, certification of unfunded property (a)installment Purchase contract provides for bonds to be tendered in 2003 for 3.75% and additions. 4.00% series and in 2006 for 4.55% series. Therefore, these installment purchase contracts have been classified for payments in Securitization Bonds outstanding were as those years. follows: (b) A floating interest rate is determined monthly. The rate on December 31, 2002 was 1.7%. December 31. Final 2002 2001 Under the terms of the installment purchase Payment Maturity (i~nthousands) contracts, TCC is required to pay amounts Rate Date Date 3.54 1/15/2005 1/15/2007 S128,950 $ sufficient to enable the payment of interest on 5.01 1/15/2008 5.56 1/15/2010 1/15/2010 1/15/2012 154,507 107,094 and the principal (at stated maturities and 5.96 7/15/2013 7/15/2015 214,927 upon mandatory redemptions) of related 6.25 1/15/2016 1/15/2017 191,857 pollution control revenue bonds issued to unamortized Discount (700) Total 5796>6i5 finance the construction of pollution control facilities at certain plants. In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, Senior unsecured notes outstanding were as issued $797 million of Securitization Bonds, follows: Series 2002-1. The Securitization Bonds December 31. mature at different times through 2017 and 2002 2001 (in thousands) have a weighted average interest rate of 5.4 % Rate Due percent. 2002 February 22 Cc) $ - S150.000 Total S - $150.AlOO Installment purchase contracts have been (c) A floating interest rate is determined entered into in connection with the issuance monthly. 2.56%. The rate on December 31, 2001 was of pollution control revenue bonds by governmental authorities as follows: C-11
At December 31, 2002, future annual long-term debt payments are as follows: Amount (in thousands) 2003 S 229,131 2004 75,951 2005 121,937 2006 152,900 2007 52,729 Later Years 806.860 Total Principal Amount 1,439,508 unamortized Discount (943) Total 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. 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 Impairment 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 Trust Preferred Securities Note 25 Jointly owned Electric utility Plant Note 28 Related Party Transactions 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 Year Ended December 31 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 450,740 $556,458 $571,064 $445,709 $424,953 operating Expenses 442.869 523.068 518.723 391.910 365,677 operating Income 7,871 33,390 52,341 53,799 59,276 Nonoperating Items, Net (703) 2,195 (1,675) 2,488 2,712 Interest charges 20,6845 23, 275 23,216 24,420 24.263 Income (Loss) Before Extraordinary Item (13,677) 12,310 27,450 31,867 37,725 Extraordinary Loss (5.461) Net Income (Loss) (13,677) 12,310 27,450 26,406 37,725 Preferred stock Dividend Requirements 104 104 104 104 104 Earnings (Loss) Applicable to Common stock $ (13.781) S 34-6 S 26,302 $ 37,621 December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,201,747 $1,260,872 $1,229,339 $1,182,544 $1,146,582 Accumulated Depreciation and Amortization 521.792 546,162 515,041 495.847 473.503 Net Electric utility Plant S 679,955 $ 714,710 $ 714,298 5 686,697 $ 673,079 Total Assets $ 877,175 51,087. 504 $ 861,205 $,819,446 Common stock and Paid-in Capital $ 139,565 $ 139,565 $ 139,565 $ 139,565 S 139,565 Accumulated other Comprehensive Income (LosS) (30,763) Retained Earnings 71.942 105.970 122,588 113,242 114.940 Total Common Shareholder's Equity $1&80,744 $_241S53-5 $_262 153 S_252 s807 S 254,505 Cumulative Preferred stock: Not subject to Mandatory Redemption S 2,367 255.7 $S_22 _N S 68 Long-term Debt (a) $ 132,50 S 255,967 Total Capitalization And Liabilities S 877L21Z5 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 TNC service territory. As a result of the known as West Texas Utilities Company formation of the affiliated REP, effective (WTU), is a public utility engaged in the January 1, 2002, TNC no longer supplies generation, purchase, sale, transmission and electricity directly to retail customers. The distribution of electric power in west and implementation of REPs as suppliers to retail central Texas. TNC also sells electric power customers has caused a significant shift in at wholesale to other utilities, municipalities, TNC s sales as described below under rural electric cooperatives and beginning in "Results of Operations. 2002 to its affiliated retail electric provider (REP) in Texas. In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed Wholesale power marketing activities are the obligations of the affiliated REP under the conducted on TNC s behalf byAEPSC. TNC, Texas Restructuring Legislation (see Note along with the other AEP electric operating 12). Prior to the sale, during 2002, sales to subsidiaries, shares in AEP s electric power the affiliated REP were classified as Sales to transactions with other utility systems and AEP Affiliates. Subsequent to the sale, power marketers. transactions with the REP will be classified as Wholesale Electricity or Energy Delivery. On January 1, 2002, customer choice of electricity supplier began in the Electric Results of Operations Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and In 2002, Net Income decreased $26.0 million Southwest Power Pool (SPP) regions of or 211 % primarily due to a $38.1 million long-Texas, with the majority of its operations lived asset impairment charge ($24.8 million being in the ERCOT territory. net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a Under the Texas Restructuring Legislation, $4.7 million impairment charge ($3.1 million each electric utility was required to submit a net of tax) related to the abandonment of a plan to structurally unbundle its business into wind-powered generation facility (see Note an affiliated REP, a power generator, and a 13). transmission and distribution utility. During the year 2000, TNC submitted a plan for Changes in Operatina Revenues separation that was subsequently approved Increase (Decrease) From Previous Year by the PUCT. TNC has functionally separated (in millions) h its generation from its transmission and distribution operations and AEP formed a wholesale Electricity* S(231. 7) (63) separate affiliated REP. Pending regulatory Energy Delivery* (95.7) (57) approval, TNC anticipates legally separating sales to AEP Affiliates 221.7 N.M. its generation from its transmission and Total (19) (*)05.7) distribution operations (see Note 8). The *Reflects the allocation of certain affiliated REP, a separate legal entitythatwas transmission and distribution revenues an AEP subsidiary (not owned by or included in bundled retail rates to energy delivery. consolidated with TNC) was sold in December 2002 (see Note 12). N.M. = Not Meaningful Since the affiliated REP is the electricity Wholesale Electricity revenues decreased as supplier to retail customers in the ERCOT a result of the elimination of TNCs retail area, TNC sells its generation to the affiliated electricity sales in the ERCOT region as of REP and other market participants and January 1,2002 and a decrease in wholesale provides transmission and distribution power marketing margins, partially offset by services to retail customers of the REPs inthe the ICR adjustments (see Note 6). D-2
Sales to AEP Affiliates increased primarily electricity at a significantly lower price than its due to increased revenues from the newly current cost to generate electricity, TNC created affiliated REP. Although TNC sold proposed in September 2002 to Inactivate electricity to the affiliated REP instead of various, high-cost gas fired generating directly to retail customers in the ERCOT facilities. TNC recorded an impairment region, total revenues decreased due to lower charge in the third quarter 2002 of prices for power sold to the affiliated REP. approximately $34.2 million related to these plants, which was recorded in Asset Additionally, delivery charges provided to the Impairments expense. In the fourth quarter affiliated REP in 2002 are classified as Sales 2002, an additional asset impairments charge to AEP Affiliates in 2002, whereas in 2001 of $3.9 million was also recorded in they were classified as Energy Delivery connection with these plants, along with a revenue. $4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, Changes in Operating Expenses a $1.2 million charge associated with fuel Increase (Decrease) From Previous Year inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (in millions) % (recorded in Other Operations) was recorded Fuel S(76.7) (43) in the fourth quarter of 2002 related to the Purchased Power: wholesale "inactivated plants. Electricity 10.0 14 AEP Affiliates (19 . 1) (34) other operation (6.3) (6) Depreciation and Amortization expense Asset Impairments 42.9 N.M. decreased due to the elimination in 2002 of Maintenance Depreciation and excess earnings expense under Texas Amortization (7.1) (14) Taxes other Restructuring Legislation and the elimination Than Income Taxes (5.8) (21) of regulatory asset amortization that ended in Income Taxes (18.1) N.M. Total gun 2) (15) 2001. N.M. = Not Meaningful The decrease in Taxes Other Than Income Fuel expense decreased due to adecrease in Taxes is primarily a result of one time 2001 the average unit cost of fuel and decreased assessments and a decrease in the gross generation required due to decreased energy receipts tax due to deregulation. sales. TNC used natural gas as fuel for 42% of its generation in 2002. The nature of the The decrease in Income Taxes is primarily a natural gas market is such that both long-term result of a decrease in pre-tax income and short-term contracts are generally based resulting from the impairment of various on the current spot market price. Changes in generating facilities. natural gas prices affect TNC s fuel expense; however, they generally did not impact results Other Changes of operations in 2001 due to fuel recovery mechanisms, which are no longer in place Nonoperating Income and Nonoperating beginning with deregulation in 2002. Expenses increased significantly as a result of increased non-utility revenue and expenses The net decline in total Purchased Power associated with energy related construction expense in 2002 was mainly due to both projects for third parties, offset in part by reduced MWHs purchased and reduced decreased interest income. The revenues prices, partially offset by ICR adjustments associated with the aforementioned energy (see Note 6). related construction projects included in Nonoperating Income increased $45.5 million Other Operation expense decreased slightly in 2002. The expenses associated with these in 2002 due to lower factoring and projects included in Nonoperating Expenses transmission expenses, offset in part by a increased $43.0 million in 2002.
$1.4 million write-down of material and supply inventory associated with the impaired plants. Interest Charges declined primarily due to As a result of TNC s recent ability to purchase lower interest rates.
D-3
it, AEP TEXAS NORTH COMPANY Statements of Operations Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $136,962 $368,741 $376,206 Energy Delivery 73,353 169,036 176,204 Sales to AEP Affiliates 240,425 18.681 18,654 TOTAL OPERATING REVENUES 450.740 556.458 571,064 OPERATING EXPENSES: Fuel 100,466 177,140 183,154 Purchased Power: wholesale Electricity 80,391 70,395 68,080 AEP Affiliates 37,582 56,656 57,773 Other operation 104,960 111,248 93,078 Asset Impairments 42,898 Maintenance 22,295 22,343 21,241 Depreciation and Amortization 43,620 50,705 55,172 Taxes other Than Income Taxes 22,471 28,319 25,321 Income Tax Expense (Credit) (11.814) 16.262 14,904 TOTAL OPERATING EXPENSES 442.869 523.068 518.723 OPERATING INCOME 7,871 33,390 52,341 NONOPERATING INCOME 53,763 12,199 9,530 NONOPERATING EXPENSES 54,755 10,695 12,664 NONOPERATING INCOME TAX CREDIT (289) (691) (1,459) INTEREST CHARGES 20.845 23.275 23.216 NET INCOME (LOSS) (13,677) 12,310 27,450 PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK > t12 20l6 $ 27,3A6 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME (LOSS) $(13,677) $12,310 $27,450 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (15) Minimum Pension Liability -(30.74) COMPREHENSIVE INCOME (LOSS) 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 Jed December 31. 2002 2001 2000 (in thousands) BEGINNING OF PERIOD $105,970 i;122,588 $113,242 NET INCOME (LOSS) (13,677) 12,310 27,450 DEDUCTIONS: cash Dividends Declared: Common Stock 20,247 28,824 18,000 Preferred stock 104 104 104 BALANCE AT END OF PERIOD 7192A2 $1I0,7=0 The common stock of TNC is owned by a who77y owned subsidiary of AEP. see notes to Financial Statements beginning on page L-1. D-5
AEP TEXAS NORTH COMPANY Balance Sheets December 31, 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 353,087 $ 443,508 Transmission 254,483 250,023 Distribution 445,486 431,969 General 111,679 112,797 Construction Work in Progress 37.012 22.575 Total Electric Utility Plant 1,201,747 1,260,872 Accumulated Depreciation and Amortization 521.792 546.162 NET ELECTRIC UTILITY PLANT 679 955 714,710 OTHER PROPERTY AND INVESTMENTS 1,213 24.933 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2.248
- 8.327 CURRENT ASSETS:
Cash and Cash Equivalents 1,219 2,454 Accounts Receivable: Customers 62,660 18,720 Affiliated Companies 43,632 8,656 Allowance for Uncollectible Accounts (5,041) (196) Fuel Inventory 12,677 8,307 Materials and Supplies 9,574 11,190 Accrued utility Revenues 6,829 Energy Trading and Derivative Contracts 4,130 10,240 Prepayments and other 1,070 966 TOTAL CURRENT ASSETS 136.750 60,337 REGULATORY ASSETS 45,097 54,122 DEFERRED CHARGES 11 912 2.446 TOTAL ASSETS $877.175 _$_8_64,875 See Notes to Financia7 Statements beginning on page L-1. 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 $137,214 $137, 214 Paid-in Capital 2,351 2,351 Accumulated other Comprehensive Income (Loss) (30,763) Retained Earnings 71.942 105.970 Total Common shareholder s Equity 180,744 245,535 Cumulative Preferred Stock Not subject to Mandatory Redemption 2,367 2,367 Long-term Debt 132. 500 220,967 TOTAL CAPITALIZATION 468.869 OTHER NONCURRENT LIABILITIES 28, 861 6,296 CURRENT LIABILITIES: short-term Debt Affiliates 125,000 Long-term Debt Due within One Year 35,000 Advances from Affiliates 80,407 50,448 Accounts Payable General 32,714 33,782 Accounts Payable Affiliated Companies 76,217 11,388 customer Deposits 117 4,191 Taxes Accrued 3,697 17,358 Interest Accrued 2,776 4,762 Energy Trading and Derivative Contracts 3,801 12,402 other 17.414 9. 824 TOTAL CURRENT LIABILITIES 342,143 179 155 DEFERRED INCOME TAXES 117, 521 145.049 DEFERRED INVESTMENT TAX CREDITS 21.510 22,781 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 557 52250 REGULATORY LIABILITIES AND DEFERRED CREDITS 50,972 37.475 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $87,17 see Notes to Financia7 statements beginning on page L-1. D-7
AEP TEXAS NORTH COMPANY Statements of Cash Flows Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $(13,677) $ 12,310 $ 27,450 Adjustments to Reconcile Net Income to Net Cash Flows From operating Activities: Depreciation and Amortization 43,620 50,705 55,172 writedown of Utility Assets 38,154 writedown of wind Farm Assets 4,744 Deferred Income Taxes (12,275) (11,891) 8,164 Deferred Investment Tax credits (1,271) (1,271) (1,271) Mark-to-Market Energy Trading and Derivative Contracts (1,127) (3,506) 2,590 CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: Accounts Receivable (net) (74,071) 24,844 (1,445) Fuel, Materials and supplies (2,754) 3,187 8,478 Accrued Utility Revenues (6,829) Accounts Payable 63,761 (42,604) 28,393 Taxes Accrued (13,661) (1,543) 6,443 Fuel Recovery 14,169 32,505 (53,841) Transmission Coordination Agreement settlement 15,465 change in other Assets (16,928) (1,432) 2,549 Change in other Liabilities 16, 514 11,056 (3.869) Net cash Flows From Operating Activities 38. 369 72. 360 94,278 INVESTING ACTIVITIES: Construction Expenditures (43,563) (39,662) (64,477) sales Proceeds and other 150 (127) Net Cash used For Investing Activities (43,413) (39.789) (64,477) FINANCING ACTIVITIES: Retirement of Long-term Debt (130,799) (48,000) change in short-term Debt Affiliated (net) 125,000 Change in Advances from Affiliates (net) 29,959 (8,130) 37,170 Dividends Paid on Common stock (20,247) (28,824) (18,000) Dividends Paid on cumulative Preferred Stock (104) (104) (104) Net Cash Flows From (used For) Financing Activities 3 809 (37,058) (28.934) Net Increase (Decrease) in cash and cash Equivalents (1,235) (4,487) 867 cash and cash Equivalents at Beginning of Period 2,454 6.941 6.074 Cash and cash Equivalents at End of Period $-1,2-19 i__2,54 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) COMMON SHAREHOLDER S EQUITY $180.744 S245.535 PREFERRED STOCK: $100 par value authorized shares 810,000 Call Price shares December 31, Number of Shares Redeemed outstanding Series 2002 Year Ended December 31. December 31. 2002 2002 2001 2000 Not subject to Mandatory Redemption: 4.40% $107 - - 1 23,672 2,367 2,367 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 88,190 211,657 Installment Purchase Contracts 44,310 44,310 Less Portion Due within one Year (35 000) Long-term Debt Excluding Portion Due within one Year 132. 500 220.967 TOTAL CAPITALIZATION See Notes to Financia7 Statements beginning on page L-1. D-9
AEP TEXAS NORTH COMPANY Schedule of LonQ-term Debt First mortgage bonds outstanding were as Under the terms of the installment purchase follows: contracts, TNC is required to pay amounts December 31. sufficient to enable the payment of interest on 2002 2001 (in thousaniis-Y and the principal of (at stated maturities and % Rate Due 6-7/8 2002 October 1 S - S 35,000 upon mandatory redemptions) related 7 2004 October 1 18,469 40,000 pollution control revenue bonds issued to 6-1/8 2004 February 1 24,036 40,000 6-3/8 2005 October 1 37,609 72,000 finance the construction of pollution control 7-3/4 2007 June 1 unamortized Discount 8,151 (75) 25,000 (343) facilities at certain plants. Q8 i2IL-6S At December 31, 2002, future annual long-First mortgage bonds are secured by a first term debt payments are as follows: mortgage lien on electric utility plant. The Amount indenture, as supplemented, relating to the (in thousands) first mortgage bonds contains maintenance 2003 $ - and replacement provisions requiring the 2004 42,505 2005 37,609 deposit of cash or bonds with the trustee, or in 2006 - 2007 8,151 lieu thereof, certification of unfunded property Later Years 44 310 additions. Principal Amount Less: unamortized Discount 132,575 C75) Total S 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 Red River Authority of Texas: 6.00 2020 June 1 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. Inour 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 1 IJ .IIU
...f J. 1*
I - . 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,814,470 $1,784,259 $1,759,253 $1,586,050 $1,672,244 Operating Expenses 1,512,407 1.509.273 1.558.099 1,344,814 1.443.701 Operating Income 302,063 274,986 201,154 241,236 228, 543 Nonoperating Items, Net 20,106 6,868 11,752 8,096 (8,301) Interest Charges 116.677 120,036 148.000 128.840 126.912 Income Before Extraordinary Item 205,492 161,818 64,906 120,492 93,330 Extraordinary Gain 8.938 Net Income 205,492 161,818 73,844 120,492 93,330 Preferred stock Dividend Requirements 2.897 2.011 2,504 2.706 2.497 Earnings Applicable to common Stock $ 202,195 $ 159&0QZ December 31, 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,895,303 $5,664,657 $5,418,278 $5,262,951 $5,087,359 Accumulated Depreciation and Amortization 2.424.607 2. 296. 481 2. 188. 796 2.079.490 1.,984. 856 Net Electric Utility Plant 3229,482 SI-1MA61 Total Assets _4 &62.7 847 $6.522 l 9S 14.35Z2 V4,047,038 Common Stock and Paid-in Capital $ 977,700 $ 976,244 $ 975,676 $ 974,717 $ 924,091 Accumulated other comprehensive Income (Loss) (72,082) (340) Retained Earnings 260,439 150, 797 120, 584 175. 854 179.461 Total Common Shareholder's Equity ,166 Q5Z I 1,12-6 7 0- $1.,096,260Q $103A52 cumulative Preferred Stock: Not subject to Mandatory Redemption $ 17,790 $ 17,790 $ 17,790 $ 18,491 $ 19,359 Subject to Mandatory Redemption 10.860 10,860 10,860 20,310 22.310 Total Cumulative Preferred Stock $ 28.650 $1__3 Oi Long-term Debt (a) IL,55-6-55-9 $1,605,818 t1<6 65, _$It55L455 obligations under Capital Leases (a) L-3i,5&89 $ 46,281 $ 64,645 Si__5d751z Total Capitalization And Liabilities t{A,621T4~ $4Z482,78 $6557255 $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 2001 primarily due to the effect of a court generation, purchase, sale, transmission and decision related to a corporate owned life distribution of electric power to 925,000 retail insurance (COLI) program recorded in 2000. customers in southwestern Virginia and In February 2001, the U.S. District Court for southern West Virginia. APCo, as a member the Southern District of Ohio ruled against of the AEP Power Pool, shares in the AEP and certain of its subsidiaries, including revenues and costs of the AEP Power Pool's APCo, in a suit over deductibility of interest wholesale sales to neighboring utility systems claimed in AEP s consolidated tax return and power marketers including power trading related to COLI. In 1998 and 1999 APCo paid transactions. APCo also sells wholesale the disputed taxes and interest attributable to power to municipalities. the COLI interest deductions for taxable years 1991-98. Also contributing to the increase in The cost of the AEP Power Pool's generating net income was growth in and strong capacity is allocated among the Pool performance by the wholesale electricity members based on their relative peak business in the first half of 2001 offset in part demands and generating reserves through by the effect of extremely mild weather in the payment of capacity charges and the November and December combined with receipt of capacity credits. AEP Power Pool weak economic conditions which reduced members are also compensated for their out- retail energy sales. of-pocket costs of energy delivered to the AEP Power Pool and charged for energy Operating Revenues received from the AEP Power Pool. The AEP Power Pool calculates each company's prior Operating Revenues increased $30 million or twelve month peak demand relative to the 2% in 2002 as a result of weather related total peak demand of all member companies demand and increased generation resulting as a basis for sharing revenues and costs. from availablility of plants previously down for The result of this calculation is the member maintenance coming back online. An increase load ratio (MLR) which determines each of $25 million, or 1%, in 2001 Operating company's percentage share of revenues and Revenues was attributable to an increase in costs. AEP Power Pool transactions. Changes in components of revenues were as follows: Results of Operations Increase (Decrease) From Previous Year (dollars in millions) Net Income increased $44 million or 27% in 2002 2001 2002 due to higher retail sales resulting from Amount % Amount % wholesale increased generation, weather related El ectri ci ty* $16.0 2 S(11.7) (1) electricity demands and reductions in Energy Delivery* (1.0) Sales to AEP
- 20.1 3 Maintenance expense. Most significantly, the Affiliates 15.2 9 16.6 11 Total Mountainer, Amos and Glen Lyn plants, down Revenues 5302 2 L25 0 1 for boiler maintenance in 2001, were back
*Reflects the allocation of certain online in 2002 resulting in increased transmission and distribution revenues availability of generation and decreased included in bundled retail rates to energy delivery.
maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased $10 million as a result of Operating Revenues for 2002 increased as a a reduction in trading incentive compensation result of an increase in generation and recorded in Nonoperating Expenses offset in availability at the Mountaineer, Amos and part by decreased power trading gains Glen Lyn plants; and increases in residential recorded in Nonoperating Income. and commercial sales due to warmer weather during July and September. Sales to AEP Net Income increased $88 million or 119% in affiliates increased for the year due to an E-2
increase in generation capacity and power of an increase in APCo generation. available to be delivered to AEP Power Pool. Mountaineer, Amos, and Glen Lyn plants had These increases were partially offset by flat undergone boiler plant maintenance in 2001 industrial sales as recessionary conditions which resulted in increased availability in continued into 2002. 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of The year 2001 saw a decrease in kilowatt scheduled plant maintenance. hour sales to industrial customers. This decrease was due to the economic recession. Wholesale Electricity Purchases increased for In the fourth quarter, sales to residential and 2002 as a result of increased purchases from commercial customers declined, reflecting third parties for resale to wholesale customers recession-related reductions in demand. and to meet internal demand. Electricity purchased power expense increased in 2001 The increase in Sales to AEP Affiliates in due to increases inwholesale electricity prices 2001 isdue to an increase in AEP Power Pool and as a result of the previously mentioned transactions. As the quantity of energy sold plant outages. by the AEP Power Pool rose, APCo s contribution of energy to the Pool rose, The decrease for 2002 in Purchases from accounting for the increase in APCo s AEP Affiliates is a result of increased internal revenues from Sales to AEP Affiliates. generation due to plant availability. Purchased power from AEP affiliates decreased in 2001 Operating Expenses as the result of a decrease in AEP Power Pool capacity charges due to a reduction in Operating Expenses for 2002 were APCo s MLR. comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Other Operation expense increased in 2002 Power expenses were offset by decreases in mainly due to severance expenses related to power purchases from AEP Affiliates due to the sustained earnings initiative plan, a increases in APCo generation and availability reduction in the gains recorded on the as plants previously down for maintenance dispositions of S02 emission allowances, and resumed operations. The decrease in increased insurance premiums and other operating expenses in 2001 of 3% is due to employee benefit costs. These increases decreases in income taxes, other operation were offset by reduced trading overhead expense, fuel expense and taxes other than expenses as a result of reduced staffing and income taxes partially offset by increases in weaker market conditions; a decrease in electricity purchased power expense and transmission equalization charges caused by depreciation and amortization expenses. a reduction in APCo s MLR ratio; and energy Changes in the components of Operating delivery severance accruals recorded in 2001 Expenses are as follows: for which there was no comparable activity in Increase (Decrease) 2002. Other operation expense decreased in From Previous Year 2001 mainly due to the effect of AEPSC (dolTlars in millions) 2002 2001 billings in 2000 for the disallowance of the Amount % Amount % COLI program interest deduction. Additionally, Fuel S 79.4 23 S (17.6) (5) the decrease was the result of a gain wholesale Electricity recorded on the disposition of S02 emission Purchases 15.0 36 17.4 70 allowances offset in part by increased AEP Affiliate Purchases (112.3) (32) (8.9) (3) wholesale power trading incentive other operation 8.9 3 (18.6) (7) compensation expense. Maintenance (10.2) (8) 7.9 - 6 Depreciation and Amortization 8.9 5 17.3 11 The decrease in Maintenance expense in Taxes other Than Income Taxes (4.6) (5) (11.8) (11) 2002 is primarily due to previously discussed Income Taxes 18.0 19 (34. 5) (27) boiler plant maintenance at Amos, Total __3.1 - (3) Mountaineer and Glen Lyn plants in the year Fuel expense increased for 2002 as a result 2001. E-3
Depreciation and Amortization expense trading gains driven by a decline in market increased during 2002 due to increased prices. Nonoperating Expenses decreased as amortization for the net generation-related a result of decreased trading incentives. The regulatory assets related to the Companys increase in Nonoperating Income and West Virginia jurisdiction which were assigned Nonoperating Expenses for 2001 is due to to the distribution portion of the Companys considerable increases in the level of activity business and are being recovered through in the wholesale business s trading regulated rates. Investment in production transactions outside of the AEP System s plant in service, primarily equipment related to traditional marketing area. emission control, contributed to the increase in depreciation and amortization expense. Interest Charges Depreciation and Amortization expense Interest Charges for 2002 decreased primarily increased in 2001 due to accelerated as a result of lower AEP money pool balances amortization, beginning in July 2000, of the and interest rates and the retirement of first transition regulatory assets in the Virginia and mortgage bonds in 2001. Interest charges West Virginia jurisdictions. Additional decreased in 2001 primarily due to the effect investments in distribution and transmission of recognizing in 2000 previously deferred plant also contributed to the increases in interest payments to the IRS related to the depreciation and amortization expense in COLI disallowances and interest on resultant 2001. During June 2000 we discontinued the state income tax deficiencies. Additionally, application of SFAS 71 in the Virginia and the decrease in 2001 is due to the retirement West Virginia jurisdictions. Consequently net of first mortgage bonds in 2000. 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. 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 Year Ended December 3L. 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $1,')33,904 $1,017,938 $1,029,657 Energy Delivery 594,089 595,036 574,918 Sales to AEP Affiliates 186.477 171,285 154.678 Total Operating Revenues 1.314.470 1.784.259 1.759.253 OPERATING EXPENSES: Fuel 430,963 351,557 369,161 Purchased Power: wholesale Electricity 57,091 42,092 24,720 AEP Affiliates 234,597 346,878 355,774 Other operation 269,426 260,518 279,114 Maintenance 122,209 132,373 124,493 Depreciation and Amortization 189,335 180,393 163,089 Taxes other Than Income Taxes 95,249 99,878 111,692 Income Taxes 113.537 95. 584 130.056 Total operating Expenses 1,512.407 1,509.273 1.558.099 OPERATING INCOME 302,063 274,986 201,154 NONOPERATING INCOME 29,278 49,507 31,204 NONOPERATING EXPENSES 11,783 41,500 16,329 NONOPERATING INCOME TAX EXPENSE (BENEFIT) (2,611) 1,139 3,123 INTEREST CHARGES 116.677 120.036 148.000 INCOME BEFORE EXTRAORDINARY ITEM 205,492 161,818 64,906 EXTRAORDINARY GAIN DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) 8.938 NET INCOME 205,492 161,818 73,844 PREFERRED STOCK DIVIDEND REQUIREMENTS 2.897 2.011 2.504 EARNINGS APPLICABLE TO COMMON STOCK -$ZLn-A0 Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME $205,492 $161,818 $73,844 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (1,580) (340) Minimum Pension Liability (70,162) COMPREHENSIVE INCOME $13,50 S161,AIA see Notes to Financia7 Statements beginning on page L-1. E-5
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31. 2002 2001 2000 (in thousands) Retained Earnings January 1 $150,797 $120,584 $175,854 Net Income 205.492 161,818 73,844 356.289 282.402 249,698 Deductions: cash Dividends Declared: Common stock 92,952 129, 594 126,612 Cumulative Preferred Stock: 4-1/2% series 801 801 811 5.90% Series 278 278 307 5.92% Series 364 364 364 6.85% series 289 Total cash Dividends Declared 94,395 131,037 128,383 capital Stock Expense 1.455 568 731 Total Deductions 95.850 131.605 129.114 Retained Earnings December 31 $260,4139- $150,797 See Notes to Financia7 Statements beginning on page L-1. E-6
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31. 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,245,945 $2,093,532 Transmi ssion 1,218,108 1,222,226 Distribution 1,951,804 1,887,020 General 272,901 257,957 Construction work in Progress 206.54 5 203,922 Total Electric utility Plant 5 ,895,303 5, 664 ,657 Accumulated Depreciation and Amortization 2,424.607 2. 296. 48. NET ELECTRIC UTILITY PLANT 3,470.696 3. 368. 176 OTHER PROPERTY AND INVESTMENTS 54.653 53. 736 LONG-TERM ENERGY TRADING CONTRACTS 115,748 119,638 CURRENT ASSETS: cash and cash Equivalents 4,285 13,663 Accounts Receivable: Customers 132,266 113,371 Affiliated Companies 122,665 63,368 Mi scellaneous 28, 629 11,847 Allowance for uncollectible Accounts (13,439) (1,877) Fuel Inventory 53,646 56,699 Materials and supplies 59,886 59,849 Accrued utility Revenues 30,948 30,907 Energy Trading and Derivative Contracts 94,238 137,742 Prepayments and other 13.396 16.018 TOTAL CURRENT ASSETS 526.,520 501.587 REGULATORY ASSETS 395.,553 397. 383 DEFERRED CHARGES 64. 677 42, 265 TOTAL ASSETS see Notes to Financial Statements beginning on page L-1. 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 $ 260,458 $ 260,458 Paid-in Capital 717,242 715,786 Accumulated other comprehensive Income (Loss) (72,082) (340) Retained Earnings 260.439 150.797 Total Common Shareowner s Equity 1,166,057 1,126,701 Cumulative Preferred stock: Not subject to Mandatory Redemption 17,790 17,790 subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,738,854 1.476. 552 TOTAL CAPITALIZATION 2,933,561 2.631.903 OTHER NONCURRENT LIABILITIES 173.438 84,104 CURRENT LIABILITIES: Long-term Debt Due within One Year 155,007 80,007 Advances From Affiliates 39,205 291,817 Accounts Payable General 141,546 127,597 Accounts Payable Affiliated Companies 98,374 84,518 Taxes Accrued 29,181 55,583 Customer Deposits 26,186 13,177 Interest Accrued 22,437 21,770 Energy Trading and Derivative Contracts 69,001 121,161 other 79. 832 79.089 Total CURRENT LIABILITIES 660.769 874.719 DEFERRED INCOME TAXES 701.801 703. 575 DEFERRED INVESTMENT TAX CREDITS 33.691 38,328 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 44.517 60. 518 REGULATORY LIABILITIES AND DEFERRED CREDITS 80,070 89, 638 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $4,62L,847 A4-82, 25 See Notes to Financial statements beginning on page L-1. E-8
APPALACHIAN POWER COMPANY AND SUBSIDIARIES consolidated Statements of Cash Flows Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $ 205,492 $ 161,818 $ 73,844 Adjustments for Noncash Items: Depreciation and Amortization 189,335 180, 505 163,202 Deferred Income Taxes 16,777 42,498 8,602 Deferred Investment Tax credits (4,637) (4,765) (4,915) Deferred Power Supply Costs (net) 6,365 1,411 (84,408) Mark-to-Market of Energy Trading Contracts (21, 151) (68,254) (1,843) Provision for Rate Refunds (4,818) Extraordinary Gain (8,938) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (83,412) 134,099 (166,911) Fuel, Materials and supplies 3,016 (19,957) 18,487 Accrued Utility Revenues (41) 35,592 (13,081) Accounts Payable 27,805 (45,073) 159,369 Taxes Accrued (26,402) (7,675) 14,220 Revenue Refunds Accrued 181 Incentive Plan Accrued (858) (2,451) 10,662 Disputed Tax and Interest Related to COLI 72,440 change in operating Reserves (3,190) (5,358) (19,770) Rate Stabilization Deferral 75,601 change in other Assets (43,337) 19,418 (13,021) change in other Liabilities 14,948 (27.954) 9.817 Net Cash Flows From Operating Activities 280,710 393. 854 288. 720 INVESTING ACTIVITIES: Construction Expenditures (276, 549) (306,046) (199,285) Proceeds From sales of Property and other 1,074 1,182 159 Net Cost of Removal and Other (8.434) (7.500) Net Cash Flows used For Investing Activities (275.475) (313.298) (206. 626) FINANCING ACTIVITIES: Issuance of Long-term Debt 647,401 124,588 74,788 Retirement of cumulative Preferred stock (9,924) Retirement of Long-term Debt (315,007) (175,000) (136,166) change in short-term Debt (net) (191,495) 68,015 Change in Advances From Affiliates (252,612) 300,204 (8,387) Dividends Paid on Common stock (92,952) (129,594) (126,612) Dividends Paid on cumulative Preferred Stock (1.443) (1.443) (1.938) Net cash Flows used For Financing Activities (14,613) (72.740) (140,224) Net Increase (Decrease) in cash and Cash Equivalents (9,378) 7,816 (58,130) cash and cash Equivalents January 1 13.663 5 $847 63.977 cash and cash Equivalents December 31 $ 4,285 $ 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) COMMON SHAREHOLDER S EQUITY S1.166.057 $1.126.701 PREFERRED STOCK: No par value - authorized shares 8,000,000 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 (b): 4-1/2% $110 6 - 7,011 177,899 17.790 17.790 subject to Mandatory Redemption (b): 5.90% cc) - - 10,000 47,100 4,710 4,710 5.92% Cc) _ _ - 61, 500 6.150 6.150 10.860 10.860 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 489,697 639,365 Installment Purchase Contracts 235,027 234,904 senior unsecured Notes 1,166,609 518,247 Junior Debentures 161, 507 other Long-term Debt 2,528 2,536 Less Portion Due within one Year (155.007) (80.007) Long-term Debt Excluding Portion Due within one Year 1.738.854 1.476.552 TOTAL CAPITALIZATION 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 Under the terms of the installment purchase follows: contracts, APCo is required to pay amounts December 31. sufficient to enable the payment of interest on 2002 2001 (in thousands) and the principal of (at stated maturities and % Rate Due 7.38 2002 August 15 'S - $ 50,000 upon mandatory redemptions) related 7.40 2002 - December 1 30,000 pollution control revenue bonds issued to 6.65 2003 - May 1 40,000 6.85 2003 - June 1 30,000 finance the construction of pollution control 6.00 2003 - November 1 30,000 30,000 facilities at certain plants. 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 Senior unsecured notes outstanding were as 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 100,000 follows: 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 30,237 30, 237 December 31. 7.15 2023 - November 1 20,000 20,000 2002 2001 7.125 2024 - May 1 45,000 45,000 (in thousands) 8.00 2025 - June 1 45,000 45,000 X Rate Due unamortized Discount -1C 540) (1.872) (a) 2003 August 20 S 125,000 5125,00 0 Total M69,36 7.45 2004 - November 1 50,000 50,000 4.80 2005 June 15 450,000 - First mortgage bonds are secured by a first 4.32 2007 November 12 200,000 - 6.60 2009 - May 1 150,000 150,00 0 mortgage lien on electric utility plant. Certain 7.20 2038 - March 31 100,000 100,00 0 supplemental indentures to the first mortgage 7.30 2038 - June 30 100,000 100,00 0 unamortized Discount 8 391 6.75 lien contain maintenance and replacement Total VIA609 S51,2 z provisions requiring the deposit of cash or (a) A floating interest rate is determined bonds with the trustee, or in lieu thereof, monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, certification of unfunded property additions. respectively. Installment purchase contracts have been Junior debentures outstanding were as entered into, in connection with the issuance follows: of pollution control revenue bonds, by December 31. governmental authorities as follows: 2002 (in thousands) 2001 8-1/4% Series A due December 31. 2002 2001 2026 September 30 S - S 75,000 8% Series B due 2027 (in thousands) % Rate Due - March 31 90,000 Industrial Development unamortized Discount (3 . 493) Total U161, 50 Authority of Russell county, Virginia: At December 31, 2002, future annual long-7.70 2007 - November 1 S 17, 500 S 17, 500 5.00 2021 - November 1 19,500 19, 500 term debt payments are as follows: Putnam County, West Virginia: Amount (in thousands) 5.45 2019 - June 1 410,000 40,000 2003 S 155,007 6.60 2019 - July 1 30,000 30,000 2004 121,008 2005 530,010 Mason County, West Virginia: 2006 100,011 2007 217,513 7-7/8 2013 - November 1 10,000 10,000 Later Years 782. 216 6.85 2022 - June 1 40,000 40,000 Total Principal Amount 1,905,765 6.60 2022 - October 1 50,000 50,000 unamortized Discount (11,904) 6.05 2024 - December 1 30,000 30,000 Total unamortized Discount 1. 973) (2 096) Total 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. combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 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 Asset Impairments and Investments Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 supplementary Information Note 20 Leases Note 22 Lines of credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 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 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $1,400,160 $1,350,319 $1,304,409 $1,190,997 $1,187,745 operating Expenses 1180T3 81 1.098.142 1.108.532 968.207 975, 534 operating Income 219,779 252,177 195,877 222,790 212,211 Nonoperating Items, Net 15,263 7,738 5,153 2,709 (1,343) Interest charges 53. 869 68.015 80,828 75. 229 77.824 Income Before Extraordinary Item 181,173 191,900 120,202 150,270 133,044 Extraordinary Loss (30.024) (25. 236) Net Income 181,173 161,876 94,966 150,270 133,044 Preferred Stock Dividend Requirements 1.095 2.131 2.131 Earnings Applicable to common Stock £__1798JA1 $ 160.781 $18 139 £ 410Q9f Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric utility Plant $3,467,626 $3,354,320 $3,266,794 $3,151,619 $3,053,565 Accumulated Depreciation 1.465.174 1.377.032 1.299.697 1.210.994 1.134. 348 Net Electric utility Plant £2_Q02 ,452 $1,977,288 £1,40,625 $1,912,=21 Total Assets $Z,153,240 3$Z.2 "388 _$13 X&ZL42i $ &08Q8123 Common stock and Paid-in capital $ 616,410 $ 615,395 $ 614,380 $ 613,899 $ 613,518 Accumulated other comprehensive Income (LoSS) (59,357) Retained Earnings 290.611 176.103 99.069 246, 584 186.441 Total Common shareholder's Equity $_847 7 604 =$191 9,AH $ 713,449 $860.,483 $Z 79R9,9 cumulative Preferred stock - subject to Mandatory Redemption (a) $ 252i0f $L 25,000 Long-term Debt (a) $ _ 9 2 4. 54 5 L Z& L$ L6 1 Q6Z Obligations under Capital Leases (a) $L 72293& S 4_0ZZ0 L A42L3Z Total Capitalization R2$i_ 4 Q and Liabilities $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 Changes in the components of Operating public utility engaged in the generation, Revenues were: purchase, sale, transmission and distribution Increase (Decrease) of electric power to 689,000 retail customers From Previous Year (dollars in millions) in central and southern Ohio. CSPCo as a Amount % member of the AEP Power Pool shares in the Retail* S51 8 wholesale Marketing 3 2 revenues and costs of the AEP Power Pool's unrealized MTM (4) (22) wholesale sales to neighboring utility systems Other wholesale Electricity* 1 51 3 6 and power marketers including power trading Energy Delivery* 9 2 transactions. CSPCo also sells wholesale Sales to AEP Affiliates (10) (15) Total Revenues $5Q 4 power to municipalities.
- Reflects the allocation of certain transmission and distribution revenues The cost of the AEP Power Pool's generating included in bundled retail rates to energy delivery.
capacity is allocated among the Pool members based on their relative peak During the summer months, cooling degree demands and generating reserves through days increased 35%. For the fall season, the payment of capacity charges and receipt heating degree days increased 34%. This of capacity credits. AEP Power Pool reflects a return to more normal weather members are also compensated for their out- conditions since the weather experienced in of-pocket costs of energy delivered to the 2001 was abnormally mild. AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Operating Expenses Power Pool calculates each company's prior twelve month peak demand relative to the Operating Expenses increased in2002 mainly total peak demand of all member companies as a result of purchased power, operating as a basis for sharing AEP Power Pool expenses and state taxes. revenues and costs. The result of this calculation is the member load ratio (MLR) Changes in the components of Operating which determines each companies Expenses were: percentage share of AEP Power Pool revenues and costs. Increase (Decrease) From Previous Year (dollars in millions) Amount X Results of Operations Fuel $10 6 wholesale Purchased Net Income increased $19 million or 12% in Power 4 37 2002 due to reduced interest charges and a AEP Affiliates Purchased Power 18 6 $30 million extraordinary loss recorded in other operation Expenses 18 8 Maintenance Expense (2) (4) 2001 to recognize prepaid Ohio excise taxes Depreciation and stranded by Ohio deregulation offset by higher Amortization 4 3 Taxes other Than operating expenses. Income Taxes 25 22 Income Taxes 5 5 Total 7 Operating Revenues Fuel cost increased as a result of a 10% Operating Revenues increased in 2002 increase in generation partially offset by a mainly as a result of increased residential and slight cost decrease per ton of coal commercial sales due to demand caused by consumed. weather conditions. Wholesale Purchased Power increased in 2002 due to increased purchases from third F-2
parties for resale to wholesale customers and Nonoperating Income and Nonoperating to meet internal demand. Expense Expenses related to AEP Affiliates Purchased The decrease in Nonoperating Income in Power increased due to greater system pool 2002 is due to a reduction in net gains from capacity charges. AEP Power Pool trading transactions outside of the AEP System s traditional marketing The increase in Other Operation expenses area. The AEP Power Pool enters into power was attributable to a number of factors: trading transactions for the purchase and sale higher OPEB post retirement costs as aresult of electricity and for options, futures and of higher medical cost and lower investment swaps. CSPCo s share of the AEP Power performance, 2002 Sustained Earnings Pool s gains and losses from forward Initiative Expenses, and the 2001 reversal of electricity trading transactions outside of the a quality of service liability accrual. The AEP System traditional marketing area and increase was partially offset by a reduction in for speculative financial transactions (options, energy trading overheads reflecting reduced futures, swaps) is included in Nonoperating marketing activity. Income. The decrease reflects a reduction in electricity prices and margins due to a The increase in Taxes Other Than Income decrease in demand. Taxes in 2002 is due to an increase in property taxes and a full year of the state The decrease in Nonoperating Expenses in excise tax which replaced the state gross 2002 was due to a decrease in energy trading receipts tax during 2001. incentive compensation. The increase in Income Taxes is Nonoperating Income Tax Expense increased predominately due to an increase in state in 2002 due to increase in pre-tax taxes as a result of the State of Ohio s tax nonoperating income. legislation resulting from utility deregulation. This increase was offset in part by a decrease Interest Charges in federal taxes due to a decrease in pre-tax operating income. 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 Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity S 850,680 S 799,589 $ 856,998 Energy Delivery 492,278 483,219 398,046 sales to AEP Affiliates 57,202 67,511 49. 365 Total operating Revenues 1.400.160 1,350.319 1,304.409 OPERATING EXPENSES: Fuel 185,086 175,153 189,155 Purchased Power: Wholesale Electricity 15,023 10,957 9,879 AEP Affiliates 310,605 292,199 287,750 other operation 237,802 219,497 219,840 Maintenance 60,003 62,454 69,676 Depreciation and Amortization 131,624 127,364 99,640 Taxes other Than Income Taxes 136,024 111,481 123,223 Income Taxes 104.214 99.037 109, 369 TOTAL OPERATING EXPENSES 1,180.381 1 098.142 1.108, 532 OPERATING INCOME 219,779 252,177 195,877 NONOPERATING INCOME 26,360 32,756 20,580 NONOPERATING EXPENSES 4,308 21,095 8,070 NONOPERATING INCOME TAX EXPENSE 6,789 3,923 7,357 INTEREST CHARGES 53 869 68,015 80.828 INCOME BEFORE EXTRAORDINARY ITEM 181,173 191,900 120,202 EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (Note 2) (30.024) (25, 236) NET INCOME 181,173 161,876 94,966 PREFERRED STOCK DIVIDEND REQUIREMENTS 1.332 1.095 1.783 EARNINGS APPLICABLE TO COMMON STOCK $ 179, 841 $ ~93,13 Consolidated Statements of Comprehensive Income Year Ended December 31. 21'02 2001 2000 (in thousands) NET INCOME 18: 1,173 $161,876 $94,966 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (267) Minimum Pension Liability (M9. 090) COMPREHENSIVE INCOME $12 3261,B 6 594--9-U The common stock of the CSPCo is who7ly owned by AEP. See Notes to Financial Statements beginning on page L-1. 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 $176,103 $ 99,069 $246,584 Net Income 181,173 161.876 94.966 357,276 260.945 341.550 Deductions: cash Dividends Declared: Common Stock 65,300 82,952 240,600 Cumulative Preferred Stock 7% series 350 875 1.400 Total cash Dividends Declared 65,650 83,827 242,000 capital stock Expense 1.015 1.015 481 Total Deductions 66.665 84.842 242.481 Retained Earnings December 31 $290,611. $i176,13 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 $1,582,627 $1,574,506 Transmission 413,286 401,405 Distribution 1,208,255 1,159,105 General 165,025 146,732 Construction work in Progress 98.433 72.572 Total Electric Utility Plant 3,467,626 3,354,320 Accumulated Depreciation 1.465,174 1,377.032 NET ELECTRIC UTILITY PLANT 2,002X452 1,977.288 OTHER PROPERTY AND INVESTMENTS 35.759 40.369 LONG-TERM ENERGY TRADING CONTRACTS 77.810 73. 310 CURRENT ASSETS: cash and cash Equivalents 1,479 12,358 Advances to Affiliates 31,257 Accounts Receivable: Customers 49,566 41,770 Affiliated Companies 54,518 63,470 Miscellaneous 22,005 16,968 Allowance for uncollectible Accounts (634) (745) Fuel 24,844 20,019 Materials and supplies 40,339 38,984 Accrued Utility Revenues 12,671 7,087 Energy Trading Contracts 63,348 84,323 Prepayments and other Current Assets 7.308 28.733 TOTAL CURRENT ASSETS 306.701 312.967 REGULATORY ASSETS 257.682 262.267 DEFERRED CHARGES 72,836 56,187 TOTAL ASSETS $2,753,240 $2,722,388 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 $ 41,026 $ 41,026 Paid-in capital 575,384 574,369 Accumulated other comprehensive Income (Loss) (59,357) Retained Earnings 290.611 176,103 Total Common Shareholder s Equity 847,664 791,498 cumulative Preferred stock subject to Mandatory Redemption 10,000 Long-term Debt - General 418,626 571,348 Long term Debt Affiliated companies 160,000 TOTAL CAPITALIZATION 1,426.290 1.372.846 OTHER NONCURRENT LIABILITIES 95,460 36,715S CURRENT LIABILITIES: Long-term Debt Due within One Year General 43,000 20,500 Long-term Debt Due within One Year Affiliated Companies 200,000 short-term Debt Affiliated Companies 290,000 Advances from Affiliates 181, 384 Accounts Payable General 89,736 60,689 Accounts Payable Affiliated companies 81,599 83,697 Taxes Accrued 112,172 116,364 Interest Accrued 9,798 10,907 Energy Trading Contracts 46,375 72,082 other 36,790 36, 305 TOTAL CURRENT LIABILITIES 709.470 781,928 DEFERRED INCOME TAXES 437.771 443, 722 DEFERRED INVESTMENT TAX CREDITS 33.907 37.176 LONG-TERM ENERGY TRADING CONTRACTS 29.926 37.101 DEFERRED CREDITS 20.416 12.900 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $Za53 24Q £tZ722za83 See Notes to Financia7 Statements beginning on page L-1. F-7
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31. 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income S 181,173 $ 161,876 S 94,966 Adjustments for Noncash Items: Depreciation and Amortization 131,753 128,500 100,182 Deferred Income Taxes 23,292 24,108 (4,063) Deferred Investment Tax credits (3,269) (4,058) (3,482) Deferred Fuel Costs (net) 5,352 Mark to Market of Energy Trading Contracts (16,667) (44,680) (3,393) Extraordinary Loss 30,024 25,236 Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (3,992) 19,987 (29,737) Fuel, Materials and supplies (6,180) (7,780) 11,957 Accrued Utility Revenues (5,584) 2,551 38,479 Accounts Payable 26,949 (16,249) 81,284 Disputed Tax and Interest Related to COLI 39,483 Change in other Assets (8,027) (42,066) (121,115) change in other Liabilities (22,448) (18,769) 132.44 Net cash Flows From Operating Activities 297,000 233,444 367,590 INVESTING ACTIVITIES: Construction Expenditures (136,800) (132,532) (127,987) Proceeds From Sales and Leaseback Transactions and other 730 10.84 1. 560 Net cash Flows used For Investing Activities (136,070) (121.691) (126.427) FINANCING ACTIVITIES: change in Advances from Affiliates (net) (212,641) 92,652 88,732 Issuance of Affiliated Long-term Debt 160,000 200,000 Retirement of Preferred Stock (10,000) (5,000) (10,000) Retirement of General Long-term Debt (133,343) (314,733) (25,274) Retirement of Affiliated Long-term Debt (200,000) Change in short-term Debt (net) 290,000 (45,500) Dividends Paid on Common Stock (65,300) (82,952) (240,600) Dividends Paid on Cumulative Preferred Stock (525) (962) (1.575) Net cash Flows used For Financing Activities (171 809) (110.995) (234,217) Net Increase (Decrease) in cash and cash Equivalents (10,879) 758 6,946 Cash and cash Equivalents January 1 12.358 11,600 4.654 cash and Cash Equivalents December 31 3- 1 "79 S-1 3-5-8 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 $ 847.664 S 791.493 PREFERRED STOCK:. S100 par value authorized shares 2,500,000 525 par value - authorized shares 7,000,000 shares Number of shares Redeemed outstanding series Year Ended December 31, December 31, 2002 2002 2001 2000 Subject to Mandatory Redemption: 7.00% 100,000 50,000 100,000 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 222,797 243,197 Installment Purchase Contracts 91,275 91,220 Senior unsecured Notes 147,554 147,458 Notes Affiliated 160,000 200,000 Junior Debentures 109,973 Less Portion Due within one Year ( 43.000) (220. 500) Total Long-term Debt Excluding Portion Due within one Year 578.626 571. 348 TOTAL CAPITALIZATION S1L 42,9 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 Senior unsecured notes outstanding were as follows: follows: December 31, 2002 2001 December 31. (in thousands) 2002 2001 % Rate Due (in thousands) 7.25 2002 October 1 S - $ 14,000 % Rate Due 7.15 2002 November 1 6,500 6.85 2005 October 3 $ 36,000 S 36,000 6.80 2003 May 1 13,000 13,000 6.51 2008 February 1 52,000 52,000 6.60 2003 - August 1 25,000 25,000 6.55 2008 June 26 60,000 60,000 6.10 2003 November 1 5,000 5,000 unamortized Discount (446) (542) 6.55 2004 March 1 26,500 26, 500 Total 6.75 2004 May 1 26,000 26,000 8.70 2022 July 1 2,000 2,000 8.55 2022 August 1 15,000 15,000 Notes payable to parent company were as 8.40 8.40 2022 2022 August 15 October 15 14,000 13,000 14,000 13,000 follows: December 31, 7.90 2023 May 1 40,000 40,000 2002 2001 7.75 2023 August 1 33,000 33,000 (in thousands) 7.60 2024 May 1 11,000 11,000 % Rate Due unamortized Discount (703) (803) (a) 2002 - Sept 25 S - $200,000 Total 6.501% 2006 May 15 160.000 Total S160,00 First mortgage bonds are secured by a first (a) Redemed 9/25/02 mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage Junior debentures outstanding were as lien contain maintenance and replacement follows: provisions requiring the deposit of cash or December 31, 2002 2001 bonds with the trustee, or in lieu thereof, (in thousands) certification of unfunded property additions. % Rate Due 8-3/8 2025 Sept 30 S - S 72,843 7.92 2027 March 31 - 40,000 Installment purchase contracts have been unamortized Discount - (2.870) Total 5~ entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: At December 31, 2002, future annual long-December 31, term debt payments are as follows: 2002 2001 (in thousands) Amount % Rate Due (in thousands) 6-3/8 2020 - December 1 $48,550 $48,550 2003 S 43,000 6-1/4 2020 - December 1 43,695 43,695 2004 52,500 unamortized Discount (970) (1.02 5) 2005 36,000 Total 191,m 2006 160,000 2007 Later Years 332.245 Under the terms of the installment purchase Total Principal Amount 623,745 contracts, CSPCo is required to pay amounts unamortized Discount (2.119) Total 5621 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. combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 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 Asset Impairments 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 supplementary Information Note 20 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 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 AND SUBSIDIARIES Selected Consolidated Financial Data Yeair Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,526,764 $1, 526,997 $1,488,209 $1,351,666 $1,405,794 operating Expenses 1.375,575 1.367,292 1.522.911 1.243,014 1,239,787 operating Income (Loss) 151, 189 159,705 (34,702) 108,652 166,007 Nonoperating Items, Net 16,726 9,730 9,933 4,530 (839) Interest charges 93.923 93. 647 107. 263 80.406 68.540 Net Income (Loss) 73,992 75,788 (132,032) 32,776 96,628 Preferred stock Dividend Requirements 4.601 4.621 4,885 4.824 Earnings (Loss) Applicable to Common stock $ 71,167 $ 27,891 December 31, _ _ _ _ 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric utility Plant $5,029,958 $4,923,721 $4,871,473 $4,770,027 $4,631,848 Accumulated Depreciation and Amortization 2,568.604 2.436.972 2.280.521 2.194.397 2.081, 355 Net Electric Utility Plant $2,.461,3~54 $2,486, 749 $2.,590.,952 $2,5575,30 $2.,550.,493 Total Assets i48L28719 common stock and Paid-in capital $ 915,144 $ 789,800 $ 789,656 $ 789,323 $ 789,189 Accumulated other comprehensive Income (LoSS) (40,487) (3,835) Retained Earnings 143.996 74,605 3,443 166.389 2 53.154 Total Common shareholder's Equity $108,11 $ 8,36 S 793,0996 $ 9,552, $1 273 cumulative Preferred stock: Not subject to Mandatory Redemption S 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 subject to Mandatory Redemption (a) 64.945 64, 945 64,945 64.945 68.445 Total Cumulative Preferred stock $163,046 $£ 74.193 $ 7-7.718 Long-term Debt (a) $1, 617,062 11,652-Q&Z $1,388,939 $1,324, 3-26 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 maintenance costs incurred as part of generation, purchase, sale, transmission and planned and unplanned outages at Cook distribution of electric power to 571,000 retail Plant and Rockport Plant. customers in its service territory in northern and eastern Indiana and a portion of During 2000 both of the Cook Plant nuclear southwestern Michigan. As a member of the units were successfully restarted after being AEP Power Pool, I&M shares the revenues shutdown in September 1997 due to and the costs of the AEP Power Pool's questions regarding the operability of certain wholesale sales to neighboring utilities and safety systems which arose during a NRC power marketers. I&M also sells wholesale architect engineer design inspection (see power to municipalities and electric Note 5). cooperatives. As a result of costs incurred in 2000 to restart The cost of the AEP Power Pool s generating the Cook Plant and a disallowance of interest capacity is allocated among its members deductions for a corporate owned life based on their relative peak demands and insurance (COLI) program, Net Income generating reserves through the payment of increased in 2001 by $208 million. In capacity charges and the receipt of capacity February 2001 the U.S. District Court for the credits. AEP Power Pool members are also Southern District of Ohio ruled against AEP compensated for the out-of-pocket costs of and certain of its subsidiaries, including l&M, energy delivered to the AEP Power Pool and in a suit over deductibility of interest claimed charged for energy received from the AEP in AEP s consolidated tax return related to Power Pool. The AEP Power Pool calculates COLI. In 1998 and 1999 I&M paid the each company's prior twelve month peak disputed taxes and interest attributable to the demand relative to the total peak demand of COLI interest deductions for the taxable years all member companies as a basis for sharing 1991-98 and deferred them. The deferrals revenues and costs. The result of this were expensed and impacted Net Income in calculation is each company's member load 2000. ratio (MLR) which determines each company's percentage share of revenues and costs. Operatina Revenues Increase Under unit power agreements, I&M Operating Revenues were flat in 2002 and purchases AEGCo's 50% share of the 2,600 increased 3% in 2001. The 2001 increase MW Rockport Plant capacity unless it is sold reflects increased sales to AEP affiliates to other utilities. AEGCo is an affiliate that is through the AEP Power Pool. The following not a member of the AEP Power Pool. An analyzes the changes in Operating Revenues: agreement between AEGCo and KPCo Increase (Decrease) provides for the sale of 390 MW of AEGCo s From Previous Year (dollars in milions) Rockport Plant capacity to KPCo through 2002 2001 2004. The KPCo agreement extends until Amount % Amount % December 31, 2009 for Rockport Unit I and Retail* $ 28.2 4 S (2.3) N.M until December 7, 2022 for Rockport Plant Marketing 2.6 1 (12.0) (4) other 2.6 6 5 .0 13 Unit 2 if AEP s restructuring settlement Total wholesale agreement filed with the FERC becomes Electricity 33.4 3 (9.3) (1) operative. Therefore, l&M purchases 910 MW Energy of AEGCo's 50% share of Rockport Plant Dellvery* 7.3 2 3.4 1 capacity. sales to AEP Affiliates (40 ) (16) 44.7 21 Total ) N.M. 3.3 3 Results of Operations N.M. = Not Meaningful
*Reflects the allocation of certain During 2002 Net Income decreased by $2 transmission and distribution revenues million due to increased operations and included in bundled retail rates to energy delivery.
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The increase in Operating Revenues in 2001 Plant nuclear units for restart with their return is primarily due to increased sales to AEP to service in 2000. Maintenance expense affiliates reflecting increased availablility of the increased for nuclear maintenance costs Cook Plant. The return to service of the Cook incurred during refueling outages in 2002. Plant units increased the amount of power l&M could sell to its affiliates in the AEP The increase in Depreciation and Power Pool. Amortization charges in 2001 reflects increased generation and distribution plant Operating Expenses investments and amortization of l&M s share of deferred merger costs. Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 Due to a change in the Indiana property tax decrease was primarily due to the unfavorable law which lowered the floor percentage for COLI tax ruling and costs related to the calculating tax liability, Taxes Other Than extended Cook Plant outage and restart Income Taxes declined in 2002. Taxes Other efforts in 2000. The changes in the than Income Taxes increased in 2001 due to components of Operating Expenses were: higher real and personal property tax expense from the effect of a favorable accrual Increase (Decrease) From Previous Year adjustment of amounts recorded in December (dollars in millions) 2000 to actual expenses. 2002 2001 Amount % Amount % Income Taxes attributable to operations Fuel I'0(10.6) (4) $ 39.2 19 wholesale decreased in 2002 due to a decrease in pre-Electricity Purchases 4.7 25 4.9 36 tax operating income. The significant AEP Affiliate increase in Income Taxes attributable to Purchases (4.5) (2) (27.2) (10) operations in 2001 is due to an increase in Other operation 13.6 3 (147.7) (25) Maintenance 24.3 19 (92.6) (42) pre-tax operating income. Depreciation and Amortization 3.8 2 9.3 6 Taxes other Than Nonoperating Income. Nonoperating Income Taxes (7.8) (12) 4.9 8 Income Taxes (15.2) (28) 53.6 N.M. Expenses and Income Taxes Total I w-- 1 ) (10) N.M. = Not Meaningful The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains Fuel expense decreased in 2002 due to lower on forward electricity trading transactions average costs of fuel and a decline in nuclear outside AEP s traditional marketing area. The generation. The increase in Fuel expense in increase in Nonoperating Income in 2001 is 2001 reflects an increase in nuclear primarily due to increased net gains on generation as the Cook Plant units returned to forward electricity trading transactions outside service following the extended outage. AEP s traditional marketing area. Wholesale Electricity purchases increased in Nonoperating Expenses decreased in 2002 2002 and 2001 due to increased purchases due to decreased trading overheads and from third parties for sales for resale. AEP traders incentive compensation. Affiliates purchases declined in 2002 due to Nonoperating Expenses increased in 2001 lower purchases from AEGCo at lower costs. due to increased trading overheads and The decline in purchased power from AEP traders incentive compensation. affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP The increase in Nonoperating Income Taxes Power Pool which declined 21 %. in 2001 reflects the increase in nonoperating pre-tax income. Other Operation expense increased in 2002 primarily due to higher costs for pensions, Interest Charges other benefits and insurance. The decrease in Other Operation and Maintenance The decrease in 2001 Interest Charges expenses in 2001 was primarily due to the reflects the recognition in 2000 of deferred cessation of expenditures to prepare the Cook 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 $ 990,905 $ 957,548 $ 966,882 Energy Delivery 321,721 314,410 311,019 Sales to AEP Affiliates 214,138 255.039 210.308 TOTAL OPERATING REVENUES 1. 526. 764 1,526.997 1.488.209 OPERATING EXPENSES: Fuel 239,455 250,098 210,870 Purchased Power: wholesale Electricity 23,443 18,707 13,785 AEP Affiliates 233,724 238,237 265,475 other operation 462,707 449,115 596,861 Maintenance 151,602 127,263 219,854 Depreciation and Amortization 168,070 164,230 154,920 Taxes other Than Income Taxes 57,721 65,518 60,622 Income Taxes 38. 853 54.124 524 TOTAL OPERATING EXPENSES 1. 375. 575 1.367,292 1.522.911 OPERATING INCOME (LOSS) 151,189 159,705 (34,702) NONOPERATING INCOME 93,739 97,810 76,499 NONOPERATING EXPENSES 71,029 83,037 62,377 NONOPERATING INCOME TAXES 5,984 5,043 4,189 INTEREST CHARGES 93. 923 93 647 107.263 NET INCOME (LOSS) 73,992 75,788 (132,032) PREFERRED STOCK DIVIDEND REQUIREMENTS 4.601 4.621 4,624 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK S 71,167 $ 315,2656) Consolidated Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME (LOSS) $ 73,992 $75,788 $(132,032) OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 3,835 (3,835) Cash Flow Power Hedge (286) Minimum Pension Liability (40,201)
-Z2 COMPREHENSIVE INCOME (LOSS) $ 37, 5113Z-02) see Notes to Financia7 statements beginning on page L-1.
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INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Eamings Year Ended December 31. 2002 2001 2000 (in thousands) Retained Earnings January 1 $ 74,605 S 3,443 $ 166,389 Net Income (Loss) 73, 992 75.788 (132.032) 148, 597 - 79.231 34. 357 Deductions: cash Dividends Declared: Common stock 26,290 cumulative Preferred stock: 4-1/8% series 229 229 230 4.56% Series 66 66 66 4.12% series 52 72 74 5.90% series 897 897 897 6-1/4% series 1,203 1,203 1,203 6.30% series 834 834 834 6-7/8% series 1.186 1.186 1,186 Total Cash Dividends Declared 4,467 4,487 30,780 capital stock Expense 134 139 134 Total Deductions 4.601 4.626 30.914 Retained Earnings December 31 $143 S 74,6L05 $3 1A443 See Notes to Financia7 statements beginning on page L-1. G-6
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31. 2002 2001 (in thousand S) ASSETS ELECTRIC UTILITY PLANT: Production $2,768,463 $2,758,160 Transmission 971,599 957,336 Distribution 921,835 900,921 General (including nuclear fuel) 220,137 233,005 Construction work in Progress 147.924 74.299 Total Electric Utility Plant 5,029,958 4,923,721 Accumulated Depreciation and Amortization 2.568,604 2,436.972 NET ELECTRIC UTILITY PLANT 2.461. 354 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 120,941 127.977 CURRENT ASSETS: cash and cash Equivalents 3,237 16,804 Advances to Affiliates 191,226 46,309 Accounts Receivable: Customers 67,333 60,864 Affiliated Companies 122,489 31,908 Miscellaneous 30,468 25,398 Allowance for uncollectible Accounts (578) (741) Fuel 32,731 28,989 Materials and Supplies 95,552 91,440 Energy Trading and Derivative Contracts 68,148 108,895 Accrued Utility Revenues 6,511 2,072 Prepayments and other 11,899 6.497 TOTAL CURRENT ASSETS 629.016 418.435 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 $ 56,584 $ 56,584 Paid-in Capital 858,560 733,216 Accumulated other Comprehensive Income (Loss) (40,487) (3,835) Retained Earnings 143 996 74.605 Total Common shareholder's Equity 1,018,653 860,570 cumulative Preferred Stock: Not subject to Mandatory Redemption 8,101 8,736 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1.587,062 1.3123082 TOTAL CAPITALIZATION 2,678, 761 2.246. 333 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 620,672 600,244 other 138.965 87,025 TOTAL OTHER NONCURRENT LIABILITIES 759.637 687,269 CURRENT LIABILITIES: Long-term Debt Due within one Year 30,000 340,000 Accounts Payable General 125,048 86,766 Accounts Payable - Affiliated Companies 93,608 43,956 Taxes Accrued 71,559 69,761 Interest Accrued 21,481 20,691 obligations under capital Leases 8,229 10,840 Energy Trading and Derivative Contracts 48,568 93,413 other 92. 822 76 486 TOTAL CURRENT LIABILITIES 491,315 741.913 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 REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 92,039 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 2000 (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $ 73,992 $ 75,788 $ (132,032) Adjustments for Noncash Items: Depreciation and Amortization 168,070 166,360 163,391 Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net) (26,577) 418 5,737 Amortization of Nuclear Outage Costs 40,000 40,000 40,000 Deferred Income Taxes (16,921) (29,205) (125,179) Deferred Investment Tax credits (7,740) (8,324) (7,854) Unrecovered Fuel and Purchased Power Costs 37,501 37,501 37,501 Changes in Certain Current Assets And Liabilities: Accounts Receivable (net) (102,283) 64,841 (25,305) Fuel, Materials and Supplies (7,854) (19,426) 10,743 Accrued utility Revenues (4,439) (2,072) 44,428 Accounts Payable 87,934 (60,185) 85,056 Taxes Accrued 1,798 1,345 19,446 Mark-to-Market of Energy Trading and Derivatives Contracts (9,517) (62,647) 14,830 Disputed Tax and Interest Related to COLI 56,856 Regulatory Asset Trading Losses (992) 8,493 (17,914) Regulatory Liability Trading Gains 2,494 34,293 (7,416) change in other Assets (28,233) (5,871) (68,160) Change in other Liabilities 21.001 (5,102) 37.309 Net cash Flows From Operating Activities 228.234 236,207 131.437 INVESTING ACTIVITIES: Construction Expenditures (167,484) (91,052) (171,071) Bu yout of Nuclear Fuel Leases (92,616) Other 1. 759 1,074 587 Net Cash Flows Used For Investing Activities (165 .72 5) (182.594) (170.484) FINANCING ACTIVITIES: capital Contributions from Parent Company 125,000 Issuance of Long-term Debt 288,732 297,656 199,220 Retirement of cumulative Preferred Stock (424) (314) Retirement of Long-term Debt (340,000) (44,922) (148,000) change in Advances from Affiliates (net) (144,917) (299,891) 253, 582 change in short-term Debt (net) (224,262) Dividends Paid on Common stock (26,290) Dividends Paid on cumulative Preferred stock (4.467) (4.487) (3. 368) Net cash Flows From (Used For) Financing Activities (76.076) (51.644) . 50. 568 Net Increase (Decrease) in cash and cash Equivalents (13,567) 1,969 11,521 cash and Cash Equivalents January 1 16.804 14.835 3,314 cash and cash Equivalents December 31 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) COMMON SHAREHOLDER S EQUITY $1.018.653 S 860.570 PREFERRED STOCK: $100 Par value - Authorized 2,250,000 shares $25 Par value - Authorized 11,200,000 shares 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-$100 Par: 4-1/8% 106.125 20 - 3,750 55,369 5,537 5,539 4.56% 102 - - - 14,412 1,441 1,441 4.12% 102.728 6,326 - 1,375 11,230 1.123 i1. 756 8.101 8.736 Subject to Mandatory Redemption-S100 Par(b): 5.90% (c) - - - 152,000 15,200 15,200 6-1/4% (c) - - - 192,500 19,250 19, 250 6.30% (c) - - - 132,450 13,245 13,245 6-7/8% (d) - - - 172,500 17.250 174950 64.945 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 SZ,2A33 4S2j1 (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 The terms of* the installment purchase follows: contracts require l&M to pay amounts December 31. 2002 2001 sufficient for the cities to pay interest on and (in thousands) the principal of (at stated maturities and upon % Rate Due 7.60 2002 November 1.S $ 50,000 mandatory redemptions) related pollution 7.70 2002 December 15- 40,000 control revenue bonds issued to finance the 6.10 2003 - November 1 30,000 30,000 8.50 2022 - December 15 75,000 75,000 construction of pollution control facilities at 7.35 7.20 2023 2024 October 1 February 1 15,000 30,000 15,000 30,000 certain generating plants. The term rate 7.50 2024 March 1 25.000 25,000 bonds due 2025 are subject to mandatory unamortized Discount (75 5) (859) tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate First mortgage bonds are secured by a first bonds have been classified for repayment mortgage lien on electric utility plant. Certain purposes in 2007 (the term end date). supplemental indentures to the first mortgage lien contain maintenance and replacement Senior unsecured notes outstanding were as provisions requiring the deposit of cash or follows: December 31. bonds with the trustee, or in lieu thereof, 2002 2001 certification of unfunded property additions. (in thousands)
% Rate Due (a) 2002 September 3 S - $200,000 6-7/8 2004 3uqy 1 150,000 150,000 Installment purchase contracts have been 6.125 2006 December 15 300,000 300,000 entered in connection with the issuance of 6.45 2008 November 10 50,000 50,000 6.375 2012 November 1 100,000 pollution control revenue bonds by 6 2032 December 31 150,000 governmental authorities as follows: unamortized Discount (2.973)
S7AL02 (3.856) December 31. (a) A floating interest rate was determined 2002 2001 quarterly. The rate on December 31, 2001 (in thousands) was 2.71%. The average interest rates were % Rate Due 2.6% in 2002 and 5.1% in 2001. City of Lawrenceburg, Indiana: 7.00 2015 April 1 S 25,000 S 25,000 5.90 2019 - November 1 52,000 52,000 Junior debentures outstanding were as city of Rockport, Indiana: follows: (a) 2014 August 1 50,000 December 31. 7.60 2016 March 1 40,000 40,000 2002 2001 6.55 2025 June 1 50,000 50,000 -in thousands) (b) 2025 June 1 50,000 50,000 % Rate Due 4.90(c) 2025 June 1 50,000 8.00 2026 March 31 S 40,000 S 40,000 7.60 2038 June 30 125,000 125,000 city of Sullivan, Indiana: unamortized Discount (3 282) (3.389) 5.95 2009 May 1 45,000 45,000 Total S161 71 unamortized Discount (1.664) (1 761) I1t3036 S1 3 Interest may be deferred and payment of (a) A variable interest rate was determined principal and interest on the junior debentures weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001. is subordinated and subject in right to the (b) In June 2001 an auction rate was prior payment in full of all senior indebtedness established. Auction rates are determined by standard procedures every 35 days. The of I&M. 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 At December 31, 2002, future annual long-1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate term debt payments are as follows: was a daily, weekly, commercial paper or Amount term rate as designated by I&M. A weekly (in thousands) rate was selected which ranged from 1.9% 2003 S 30,000 to 4.9% in 2001 and averaged 3.3% during 2004 150,000 2001. 2005 (c) Rate is fixed until June 1, 2007 (term 2006 300,000 rate bonds). 2007 50,000 Later Years 1.095.736 Total Principal Amount 1,625,736 unamortized Discount (8.674) Total 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. Combined Footnote Reference significant Accounting Policies Note 1 Merger Note 4 Nuclear Plant Restart Note 5 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 Asset Impairments 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 Supplementary Information Note 20 Leases Note 22 Lines of credit and Sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Related Party Transactions 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 1999 1998 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 378,683 $ 379,025 $ 389,875 $ 358,757 $ 362,999 Operating Expenses 336.486 331. 347 340.137 304.082 311.106 Operating Income 42,197 47,678 49,738 54,675 51,893 Nonoperating Items, Net 5,206 1,248 2,070 (327) (1,726) Interest Charges 26.836 27. 361 31.045 28.918 28.491 Net Income $ 20,567 $ 21,565 20,76i3 $ 2iA3A0 kS _21,676 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric utility Plant $1,295,619 $1,128,415 $1,103,064 $1,079,048 $1,043,711 Accumulated Depreciation and Amortization 397, 304 384.104 360.648 340.008 315. 546 Net Electric Utility Plant $ 744,311 S 742,416 $ 739.040 $ 728 165 Total Assets $1,164,676 S 999,048 $1,494,543 $ 986.123 $ 921,3A7 Common Stock and Paid-in Capital $ 259,200 $ 209,200 $ 209,200 $ 209,200 $ 199,200 Accumulated Other comprehensive Income (LoSS) (9,451) (1,903) Retained Earnings 48.269 57.513 67.110 71.,452 Total Common shareholder's Equity Si248 0-18 S_266,713 $ 2 6,310 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, Results of Operations purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in Net Income for 2002 decreased $1 million or 5%. eastern Kentucky. KPCo as a member of the Total Revenues were flat while increases in AEP Power Pool shares in the revenues and Operating Expenses, driven by expenses related costs of the AEP Power Pool's wholesale sales to to planned outages at the Big Sandy plant, were neighboring utility systems and power marketers offset by comparable gains in net nonoperating including power trading transactions. KPCo also income which benefited from decreases in trading sells wholesale power to municipalities. incentive compensation. The cost of the AEP Power Pool's generating Changes in Revenues capacity is allocated among the Pool members based on their relative peak demands and Increase (Decrease) generating reserves through the payment of Year-to-Date (dollars in milions capacity charges and the receipt of capacity Amount % credits. AEP Power Pool members are also wholesale Electricity* $13 6 Energy Delivery* compensated for their out-of-pocket costs of Sales to AEP Affiliates j!) C(34) Total energy delivered to the AEP Power Pool and charged for energy received from the AEP Power *Reflects the allocation of certain transmission and distribution revenues included in bundled Pool. The AEP Power Pool calculates each retail rates to energy delivery. company's prior twelve month peak demand relative to the total peak demand of all member Revenues in 2002 were comparable to those of companies as a basis for sharing revenues and last year. Increased sales to retail electricity costs. The result of this calculation is the member customers reflecting warmer summer weather, load ratio (MLR) which determines each colder days in late 2002, and increased fuel company's percentage share of AEP Power Pool recovery revenues were offset by lower Sales to revenues and costs. AEP Affiliates resulting from planned outages in 2002. KPCo s decreased generation was due to KPCo has a unit power agreement with AEGCo, scheduled maintenance resulting in lower an affiliated company, which expires in 2004. The availability in the fourth quarter. unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until Changes in Operating Expenses December 7, 2002 for Rockport Plant Unit 2 if AEP s settlement restructuring agreement filed Increase (Decrease) with the FERC becomes operative. The Year-to-Date agreement provides for KPCo to purchase 15% of (dollars in millions) Amount % the total output of the two unit 2,600-mw capacity Rockport Plant. Underthe unit power agreement, Fuel S(5.6) (8) wholesale Electricity - N.M. there is a demand charge for the right to receive Purchases from AEP Affiliates 2.8 2 the power, which is payable even it the power is other operation (5.4) (9) not taken. The amount of the demand charge is Maintenance 12.6 56 Depreciation .7 2 such that when added to other amounts received Taxes other Than by AEGCo, it will enable AEGCo to recover all its Income Taxes .4 5 fixed expenses including a FERC-approved rate Income Taxes Total Operating Expenses
-E4) (4) 2 of return on common equity. N.M. = Not Meaningful 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 Nonoperating Income Taxes for 2002 have megawatt Unit 2, representing approximately 75% increased as a result of increases in pre-tax of the plants generation capacity, was off-line income for the year offset in part by prior-year tax from mid-September through the end of the year, return adjustments. thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 Other Changes increased to meet demand during the planned outages at the Big Sandy plant. Nonoperating Income for 2002 decreased as a result of AEP s previously announced plan to Other Operation expense decreased in 2002 due reduce trading activity, and decreased margins on to reduced consumption of emission allowances power trading activity outside of the AEP due to the planned outage; reduced accruals for System s traditional marketing area resulting from trading incentive compensation due to reduced soft market demand. Nonoperating Expenses trading activity; and improvements intransmission decreased in 2002 as a result of decreases in expense resulting from less wholesale activity and trading incentive compensation. 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). Maintenance expense increased in2002 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 Ended December 31. 2002 2001 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $218,665 $205,476 $226,708 Energy Delivery 132,054 131,183 121,346 Sales to AEP Affiliates 27,964 42. 366 41.821 TOTAL OPERATING REVENUES 378.683 379.02 5 389,875 OPERATING EXPENSES: Fuel 65,043 70,635 74,638 Purchased Power: wholesale Electricity 29 86 1,940 AEP Affiliates 133,002 130,204 127,707 other operation 52,892 58,275 52,495 Maintenance 35,089 22,444 25,866 Depreciation and Amortization 33,233 32,491 31,028 Taxes other Than Income Taxes 8,240 7,854 7,251 Income Taxes 8.958 9. 358 19,212 TOTAL OPERATING EXPENSES 336,486 331, 347 340.137 OPERATING INCOME 42,197 47,678 49,738 NONOPERATING INCOME 7,863 10,881 6,139 NONOPERATING EXPENSES 753 8,949 2,940 NONOPERATING INCOME TAXES 1,904 684 1,129 INTEREST CHARGES 26,836 27. 361 31.045 NET INCOME 20.567 La25=U6 L 20,76 Statements of Comprehensive Income Year Ended December 31, 2002 2001 2000 (in thousands) NET INCOME $ 20,5b7 $21,565 $20,763 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 2,225 (1,903) Minimum Pension Liability (9.773) COMPREHENSIVE INCOME $1 3, ol Statements of Retained Earnings Year Ended December 31. 2002 2001 2000 (in thousands) RETAINED EARNINGS JANUARY 1 $48,833 $57,513 $67,110 NET INCOME 20,567 21,565 20,763 CASH DIVIDENDS DECLARED 21,131 30.245 30.360 RETAINED EARNINGS DECEMBER 31 $A& See Notes to Financial statements beginning on page L-1. H4
KENTUCKY POWER COMPANY Balance Sheets December 31. 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 275,121 S 271,070 Transmission 373,639 374,116 Distribution 425,817 402,537 General 55,913 65,059 Construction Work in Progress 165.129 15.633 Total Electric Utility Plant 1,295,619 1,128,415 Accumulated Depreciation and Amortization 397.304 384.104 NET ELECTRIC UTILITY PLANT 898.315 744.311 OTHER PROPERTY AND INVESTMENTS 6.904 6,492 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 29.871 29.477 CURRENT ASSETS: Cash and Cash Equivalents 2,304 1,947 Accounts Receivable: Customers 22,044 20,036 Affiliated Companies 23,802 16,012 Miscellaneous 2,889 3,333 Allowance for uncollectible Accounts (192) (264) Fuel 10,817 12,060 Materials and supplies 16,127 15,766 Accrued Utility Revenues 5,301 5,395 Accrued Tax Benefit 1,253 Energy Trading Contracts 24,320 33,905 Prepayments and other 2,127 1,314 TOTAL CURRENT ASSETS 110,792 109,504 REGULATORY ASSETS 101,976 97.692 DEFERRED CHARGES 16.818 11,572 TOTAL ASSETS $1,164,676 SL999,048 see Notes to Financial statements beginning on page L-1. 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 S 50,450 $ 50,450 Paid-in Capital 208,750 158,750 Accumulated other Comprehensive Income (Loss) (9,451) (1,903) Retained Earnings 48.269 48.833 Total Common Shareowner S Equity 298,018 256,130 Long-term Debt 391,632 176,093 Long-term Debt Affiliated Companies 60.000 75,000 TOTAL CAPITALIZATION 749,650 507. 223 OTHER NONCURRENT LIABILITIES 27. 319 11.929 CURRENT LIABILITIES: Long-term Debt Due within One Year - General 95,000 Long- term Debt Due within one Year - Affiliated Companies 15,000 Advances from Affiliates 23,386 66,200 Accounts Payable: General 46,515 23,464 Affiliated Companies 44,035 22,557 Customer Deposits 8,048 4,461 Taxes Accrued 10,305 Interest Accrued 6,471 5,269 Energy Trading and Derivative Contracts 17,803 38,664 other 14. 322 12,882 TOTAL CURRENT LIABILITIES 175. 580 278,802 DEFERRED INCOME TAXES 178,313 168,304 DEFERRED INVESTMENT TAX CREDITS 9,165 10,405 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 11.488 14,917 REGULATORY LIABILITIES AND DEFERRED CREDITS 13.161 7,468 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES S1,164,676 See Notes to Financial statements beginning on page L-1. H-6
KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $ 20,567 $ 21,565 $ 20,763 Adjustments for Noncash Items: Depreciation and Amortization 33,233 32,491 31,034 Deferred Income Taxes 9,839 6,293 3,765 Deferred Investment Tax credits (1,240) (1,251) (1,252) Deferred Fuel Costs (net) 2,998 (4,707) 2,948 Mark-to-Market of Energy Trading Contracts (12,267) (1,454) (4,376) change in Certain Current Assets and Liabilities: Accounts Receivable (net) (9,426) 23,694 (20,930) Fuel, Materials and supplies 882 (7,658) 8,386 Accrued Utility Revenues 94 1,105 7,237 Accounts Payable 44,529 (22,942) 39,883 Taxes Accrued (11,558) (1,580) 2,025 Disputed Tax and Interest Related to COLI .5,943 Change in other Assets (21,491) (2,762) 62,653 change in other Liabilities 16.161 (9,446) (62. 702) Net cash Flows From Operating Activities 72, 321 33, 348 95, 377 INVESTING ACTIVITIES: construction Expenditures (178,700) (37,206) (36,209) Proceeds From Sales of Property 217 216 266 Net Cash Flows Used For Investing Activities (178,483) (36 990) (35.943) FINANCING ACTIVITIES: capital contributions from Parent Company 50,000 Issuance of Long-term Debt 274,964 75,000 69,685 Retirement of Long-term Debt (154, 500) (60,000) (105,000) change in short-term Debt (net) (39,665) change in Advances From Affiliates (net) (42,814) 18,564 47,636 Dividends Paid (21.131) (30,245) (30 ,360) Net cash Flows From (used For) Financing Activities 106,519 3, 319 (57.704) Net Increase (Decrease) in cash and cash Equivalents 357 (323) 1,730 cash and cash Equivalents January 1 1$947 2,270 540 cash and cash Equivalents December 31 3-2.3-04 $ 1,947
- 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) COMMON SHAREHOLDER S EQUITY $298.018 $256.130 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 59,383 Senior unsecured Notes 352,508 147,625 Notes Payable 75,000 100,000 Junior Debentures 39,124 39,085 Less Portion Due within one Year (15.000) (95.000) Long-term Debt Excluding Portion Due within one Year 451.632 251.093 TOTAL CAPITALIZATION $7A9,6iQ 5507.2_2 See Notes to Financia7 statements beginning on page L-1. H-8
KENTUCKY POWER COMPANY Schedule of Lonq-term Debt First mortgage bonds outstanding were as Notes payable to banks outstanding were as follows: follows: December 31. 2002 2001 December 31. (in thousands) 2002 2001 % Rate Due (in thousands) 6.65 2003 May 1 S S 15,000 X Rate Due 6.70 2003 June 1 15,000 7.45 2002 September 20 S =- 6.70 2003 July 1 15,000 7.90 2023 June 1 14,500 Unamortized Discount il 17) Junior debentures outstanding were as follows: First mortgage bonds were secured by a first December 31, 2002 2001 mortgage lien on electric utility plant. (in thousands)
% Rate Due 8.72 2025 June 30 540,000 $40,000 Senior unsecured notes outstanding were as unamortized Discount (876) (915) follows: Total 539,12 539 08 December 31. Interest may be deferred and payment of 2002 2001 principal and interest on the junior debentures (in thousands)
% Rate Due is subordinated and subject in right to the (a) 2002 - November 19 S - S 70,000 6.91 2007 October 1 48,000 48,000 prior payment in full of all senior indebtedness 6.45 5.50 2008 2007 November 10 July 30,000 125,000 30,000 of the Company. 4.31 2007 November 12 80,400 - 4.37 2007 December 12 69,564 - At December 31, 2002, future annual long-unamortized Discount (456) (375) S3258S4,Z term debt payments are as follows: (a) A floating interest rate is determined Amount monthly. The rate December 31, 2001 was (in thousands) 4.3%. 2003 S 15,000 2004 Notes payable to parent company were as 2005 2006 60,000 follows: 2007 322,964 Later Years 70.000 December 31. Total Principal Amount 467,964 2002 2001 unamortized Discount (1.332) (in thousands) Total S466,-632 % Rate Due 4.336 2003 May 15 $15,000 S15,000 6.501 2006 May 15 60.000 60.000 S75,00 57,0 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. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Asset Impairments 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 Related Party Transactions 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 inthe 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. Inour 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 inthe 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 Year Ended December 3 . 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $2,113,125 $2,098,105 $2,140,331 $1,978,826 $2,105,547 operating Expenses 1.814,796 1.857, 395 1.913. 504 1.689.997 1,816.175 operating Income 298,329 240,710 226,827 288,829 289,372 Nonoperating Items, Net 5,376 18,686 (5,004) 7,000 588 Interest charges 83. 682 93.603 119,210 83.672 80,035 Income Before Extraordinary Item 220,023 165,793 102,613 212,157 209,925 Extraordinary Loss (18. 348) (18.876) Net Income 220,023 147,445 83,737 212,157 209,925 Preferred Stock Dividend Requirements 1.258 1.258 1.266 1,417 1.474 Earnings Applicable To Common stock $ 146,187 $ 82,471 LI210,740 L 20845 December 31, - A -A -- - - 2002 2001 2000 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,685,826 $5,390,576 $5,577,631 $5,400,917 $5,257,841 Accumulated Depreciation 2.566.828 2.452 571 2.764.130 2.621.711 2,461.376 Net Electric utility Plant $4.457.032,93SiIM $2.813 .50 $2 779,206 $2,796,465 Total Assets 361397.5 $4.675,5 $4,344,68 Common stock and Paid-in Capital $ 783,684 $ 783,684 $ 783,684 $ 783,577 $ 783,536 Accumulated other comprehensive Income (LoSS) (72,886) (196) Retained Earnings 522.316 401.297 398.086 587.424 587. 500 Total Common Shareholder's Equity S1A8181Z0 Cumulative Preferred stock: Not subject to Mandatory Redemption $ 16,648 $ 16,648 $ 16,648 $ 16,937 $ 17,370 subject to Mandatory Redemption (a) 8.850 8.850 8.850 8.850 11,850 Total Cumulative Preferred stock $ 2549 Long-term Debt (a) $1,067,314 SZ5__M25.4982~2~ obligations under capital Leases (a) $&65,_626 S fL8--6&66 t$A__42, 635 Total capitalization and Liabilities $4,457,03 $6.193,975 $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 of Ohio ruled against AEP and certain of its utility engaged in the generation, purchase, subsidiaries, including OPCo, in a suit over sale, transmission and distribution of electric deductibility of interest claimed in AEP s power to 702,000 retail customers in consolidated tax returns related to COLI. In northwestern, east central, eastern and 1998 and 1999 OPCo paid the disputed taxes southern sections of Ohio. OPCo supplies and interest attributable to the COLI interest electric power to the AEP Power Pool and deductions for taxable years 1991-98. The shares the revenues and costs of the AEP payments were included in Other Property Power Pool's wholesale sales to neighboring and Investments pending the resolution of this utility systems and power marketers including matter. Net Income was also favorably power trading transactions. OPCo also sells impacted by the growth in and strong wholesale power to municipalities and performance by the wholesale business. The cooperatives. effects of the COLI decision in 2000 and favorable wholesale business in 2001 were The cost of the AEP Power Pool's generating offset in part by the commencement of the capacity is allocated among Pool members amortization of transition regulatory assets in based on their relative peak demands and 2001, the effect of mild winter weather and generating reserves through the payment of the economic downturn. capacity charges or the receipt of capacity credits. AEP Power Pool members are also Operating Revenues compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and Operating Revenues increased 1% in 2002 charged for energy received from the AEP mainly as a result of increased residential and Power Pool. The AEP Power Pool calculates commercial sales due to demand caused by each company's prior twelve month peak weather conditions. Changes in the demand relative to the total peak demand of components of Operating Revenues were: all member companies as a basis for sharing Increase (Decrease) revenues and costs. The result of this From Previous Year calculation is the member load ratio (MLR) (Dollars in Millions) 2002 2001 which determines each company's Amount % Amount % percentage share of AEP Power Pool Retail* $ 11 2 S(66) (8) wholesale revenues and costs. Marketing 10 5 (19) (8) unrealized MTM 2 8 33 N.M. Other 1 1 (4) (5) Results of Operations Total wholesale Electricity* 24 2 (56) (5) Income Before Extraordinary Item increased Energy Delivery* 37 7 85 18 $54 million or 33% in 2002 mainly due to Sales to AEP reductions in operating expenses, Affiliates (46) (9) (71) (12) predominantly fuel, and interest charges. Total SL15 1 VA42) (2)
- Reflects the allocation of certain Income Before Extraordinary Item increased transmission and distribution revenues
$63 million or 62% in 2001 primarily due to included in bundled retail rates to energy delivery. the effect of a court decision related to a corporate owned life insurance (COLI) During the summer months, cooling degree program recorded in 2000. In February 2001 days increased 39%. For the fall season, the U.S. District Court forthe Southern District heating degree days increased 32%. This 1-2
reflects a return to more normal weather due to a 9% decrease in net generation conditions since 2001 weather was because of decreased sales to the AEP abnormally mild. Sales to AEP Affiliates Power Pool caused by an affiliate s two decreased due to a 15% decrease in price, nuclear units returning to service. reflective of lower average fuel cost, while MWH sales rose slightly. Wholesale Electricity Purchased Power expense increased in 2002. This was the Operating Revenues decreased 2% in 2001 result of a 11% increase of MWH sales, due to decreased sales to the AEP Power partially offset by a decrease in price. In2001 Pool. This was the result of an affiliate being the increase was due to increases in MWH able to supply more power to the Power Pool purchases from third parties because of the from two nuclear units that returned to service non-availability of associated nuclear power in June and December 2000. for resale to wholesale customers and to meet internal demand. Operating Expenses AEP Affiliates Purchased Power expense Operating Expenses decreased 2% in 2002 increased in 2002 as a result of an 18% mostly due to reductions in Fuel. Operating increase of MWH purchased from affiliates Expenses in 2001 also decreased 3%. This with a slight decrease in the average price. reduction was the result of lower Fuel and The increase for 2001 was also a result of Income Taxes partially offset by amortization increased purchases through the AEP Power of transition regulatory assets. Pool. Changes in the components of Operating Maintenance expense increased in 2001 Expenses were: mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Spom Increase (Decrease) plants, and boiler inspections at the Amos and From Previous Year (dollars in millions) Cardinal Plants. 2002 2001 Amount % Amount % In 2001, the commencement of amortization Fuel SC102) (15) 5(85) (11) of transition regulatory assets in connection wholesale Electricity Purchased Power 4 6 is 30 with the transition to customer choice and AEP Affiliates market-based pricing of retail electricity supply Purchased Power 8 14 12 23 under Ohio deregulation accounted for the Other Operation 16 4 (4) (1) Maintenance (6) (4) 18 15 significant increase in Depreciation and Depreciation and Amortization 9 4 84 54 Amortization expense. Taxes Other Than Income Taxes 10 (10) (6) Income Taxes 12 12 (86) (46) The 2002 increase in Taxes Other Than Total operating Income Taxes is the result of increases in Expenses SLU4) (2) (3) state excise tax created from a change in the The Fuel expense decrease for 2002 reflects base tax calculation. The decrease in 2001 a reduction of 19% in average cost of fuel for was due to a decrease in property tax generation, offset in part by a slight increase expense reflecting a reduction in rates on in MWH generated. The decrease in fuel generation property under the Ohio costs are the result of purchasing coal at Restructuring law partially offset by a new lower prices on the open market in 2002 state excise tax. instead of affiliated company coal. Income Taxes increased in 2002 due to an Fuel expense decreased 11 % in 2001 mainly increase in both federal and state tax 1-3
expenses. Federal taxes increased due to The major reason for the decrease in Interest higher pre-tax operating income offset in part Charges in 2001 was the recognition in 2000 by changes in certain book/tax timing of deferred interest payments to the IRS differences accounted for on aflow-thru basis. related to COLI disallowances. State taxes increased predominately as a result of the State of Ohio s tax legislation Extraordinary Loss revision involving utility deregulation. In the second quarter of 2001 an Income Taxes decreased in 2001 due to an extraordinary loss of $18 million net of tax unfavorable ruling in AEP s suit against the was recorded to write-off prepaid Ohio excise government over interest deductions claimed taxes stranded by Ohio deregulation. In 2000 relating to AEP s COLI program which was the application of regulatory accounting for recorded in 2000 and a decrease in pre-tax generation under SFAS 71 was discontinued book income. which resulted in an after tax extraordinary loss of $19 million. Nonoperating Income and Nonoperating Expense 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 $1,058,250 $1,034,026 $1,090,297 Energy Delivery 589,673 552,713 467,587 Sales to AEP Affiliates 465.202 511,366 582.447 TOTAL OPERATING REVENUES 2,113.125 2.098.105 2.140.331 OPERATING EXPENSES: Fuel 584,730 686, 568 771,969 Purchased Power: wholesale Electricity 67,385 63,441 48,657 AEP Affiliates 71,154 62,585 50,741 Other operation 416,533 400,790 404,410 Maintenance 136,609 142,878 124,735 Depreciation and Amortization 248,557 239,982 155,944 Taxes other Than Income Taxes 176,247 159,778 169,527 Income Taxes 113.581 101,373 187.521 TOTAL OPERATING EXPENSES 1.814.796 1.857. 395 1.913.504 OPERATING INCOME 298,329 240,710 226,827 NONOPERATING INCOME 51,953 70,108 57,163 NONOPERATING EXPENSES 28,567 53,802 44,009 NONOPERATING INCOME TAX EXPENSE (CREDIT) 18,010 (2,380) 18,158 INTEREST CHARGES 83.682 93.603 119.210 INCOME BEFORE EXTRAORDINARY ITEM 220,023 165,793 102,613 EXTRAORDINARY LOSS DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION Net of tax (See Note 2) (18.348) (18.876) NET INCOME 220,023 147,445 83,737 PREFERRED STOCK DIVIDEND REQUIREMENTS 1.258 1.258 1,266 EARNINGS APPLICABLE TO COMMON STOCK $ 218,765 $ 146.187 Statements of Comorehensive Income Year Ended December 31. (in thousands) 2002 2001 2000 NET INCOME $2220, 023 $147,445 $;83,737 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (542) (196) Minimum Pension Liability (72.148) COMPREHENSIVE INCOME 3 147,333 $147,249 I The common stock of oPco is wholly owned by AEP. See Notes to Financial statements beginning on page L-1. 1-5
OHIO POWER COMPANY Statement of Retained Earninqs Year Ended December 31. 2002 2001 2000 (in thousands) Retained Earnings January 1 $401,297 $398,086 $587,424 Net Income 220,023 147.445 83,737 621,320 545.531 671. 161 Deductions: cash Dividends Declared: Common stock 97,746 142,976 271,813 Cumulative Preferred Stock: 4.08% series 58 58 59 4.20% series 96 96 96 4.40% Series 139 139 139 4-1/2% Series 439 439 442 5.90% series 428 428 428 6.02% Series 66 66 66 6.35% series 32 32 32 Total Dividends 99,004 144,234 273,075 Retained Earnings December 31 MZJI-6 $AO1,291 $3-9&JO see Notes to Financia7 statements beginning on page L-1. 1-6
OHIO POWER COMPANY Balance Sheets December 31. 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,116,825 $3,007,866 Transmission 905,829 891,283 Distribution 1,114,600 1,081,122 General 260,153 245,232 Construction work in Progress 288.419 165,073 Total Electric Utility Plant 5,685,826 5,390,576 Accumulated Depreciation and Amortization 2. 566.828 2.452.571 NET ELECTRIC UTILITY PLANT 3.118.998 2.938.005 OTHER PROPERTY AND INVESTMENTS 61,686 62.303 LONG-TERM ENERGY TRADING CONTRACTS 103.230 99.706 CURRENT ASSETS: cash and Cash Equivalents 5,285 8,848 Accounts Receivable: Customers 95,100 84,694 Affiliated Companies 124,244 148,563 Miscellaneous 19,281 20,409 Allowance for uncollectible Accounts (909) (1,379) Fuel 87,409 84,724 Materials and Supplies 85,379 88,768 Energy Trading Contracts 92,108 114,280 Prepayments and other 12.083 20,865 TOTAL CURRENT ASSETS 519.980 569.772 REGULATORY ASSETS 568.641 644.625 DEFERRED CHARGES 84.497 79.662 TOTAL ASSETS SAA45 t932 4A07 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 $ 321,201 $ 321,201 Paid-in capital 462,483 462,483 Accumulated other Comprehensive Income (Loss) (72,886) (196) Retained Earnings 522. 316 401,297 Total Common Shareholder s Equity 1,233,114 1,184,785 Cumulative Preferred Stock: Not subject to Mandatory Redemption 16,648 16,648 subject to Mandatory Redemption 8,850 8,850 Long-term Debt 917.649 1.203,841 TOTAL CAPITALIZATION 2. 176.261 2.414.124 OTHER NONCURRENT LIABILITIES 227,689 130, 386 CURRENT LIABILITIES: Long-term Debt Due within One Year - General 89,665 Long-term Debt Due within one Year Affiliated Companies 60,000 short-term Debt Affiliated Companies 275,000 Advances From Affiliates 129,979 300,213 Accounts Payable General 170,563 131,057 Accounts Payable Affiliated Companies 145,718 176, 520 Customer Deposits 12,969 5,452 Taxes Accrued 111,778 126,770 Interest Accrued 18,809 17,679 obligations under Capital Leases 14,360 16,405 Energy Trading Contracts 61,839 98,081 other 80.608 90.431 Total CURRENT LIABILITIES 1,171,288 962.608 DEFERRED INCOME TAXES 794.387 797.889 DEFERRED INVESTMENT TAX CREDITS 18.748 21.925 LONG-TERM ENERGY TRADING CONTRACTS 39,702 50,459 REGULATORY LIABILITIES AND DEFERRED CREDITS 28.957 16.682 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES 54,45,032 $4,3-9A4-0173 See Notes to Financia7 Statements beginning on page L-1. 1-8
OHIO POWER COMPANY Statements of Cash Flows Year Ended December 31, 2002 2001 2000 (in thousands) OPERATING ACTIVITIES: Net Income $ 220,023 $ 147,445 S 83,737 Adjustments for Noncash Items: Depreciation, Depletion and Amortization 248,557 252,123 200,350 Deferred Income Taxes 46,010 215,833 (65,956) Deferred Investment Tax credits (3,177) (3,289) (3,399) Deferred Fuel Costs (net) (56,869) Extraordinary Loss 18,348 18,876 Mark to Market of Energy Trading Contracts (28,693) (59,833) (5,614) change in Certain Current Assets and Liabilities: Accounts Receivable (net) 14,571 51,640 51,430 Fuel, Materials and Supplies 704 4,852 46,645 Accrued Utility Revenues 3,081 264 45,311 Accounts Payable 8,704 9,887 56,069 Customer Deposits 7,517 (34,284) 31,540 Taxes Accrued (14,992) (96,331) 60,919 Disputed Tax and Interest Related to COLI 110,494 Employee Benefit and other Noncurrent Liabilities 110,298 (392,026) 145,573 Impairment Loss 1,757 change in other Assets (2,233) 79,831 (439,448) change in other Liabilities (133.154) (107.704) 359.640 Net Cash Flows From Operating Activities 478.973 86.756 639,298 INVESTING ACTIVITIES: Construction Expenditures (354,797) (344,571) (254,016) Proceeds From Sales of Property and other 6,499 16,778 6,354 Investment in coal Companies (32,115) Net Cash Flows used For Investing Activities (348,298) (359.908) (247,662) FINANCING ACTIVITIES: Issuance of Long-term Debt 300,000 74,748 change in Advances From Affiliates (net) (170,234) 392,699 (92,486) Retirement of cumulative Preferred stock (182) Retirement of Long-term Debt (140,000) (297,858) (30,663) change in short-term Debt (net) 275,000 (194,918) Dividends Paid on Common stock (97,746) (142,976) (271,813) Dividends Paid on cumulative Preferred stock (1.258) (1,258) (1,262) Net cash Flows From (Used For) Financing Activities (134.238) 250,607 (516, 576) Net Decrease in cash and cash Equivalents (3,563) (22,545) (124,940) cash and cash Equivalents January 1 8.848 31. 393 156.333 cash and cash Equivalents December 31 $ S5, 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) COMMON SHAREHOLDER S EQUITY $1.233.114 S1.184.785 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 1,460 1,460 4.20% 103.20 - - 276 22,824 2,282 2,282 4.40% 104 - - 432 31,512 3,151 3,151 4-1/2% 110 - - 2.181 97.546 9.755 9.755
- 16. 648 16.648 subject to Mandatory Redemption-S100 Par (b):
5.90% (c) $- - - 72,500 7,250 7,250 6.02% (d) - - - 11,000 1, 100 1,100 6.35% (d) - - - 5,000 500 500 8.850 8.850 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 sufficient to enable the payment of interest on follows: and the principal of (at stated maturities and December 31. 2002 2001 upon mandatory redemptions) related (in thousands) pollution control revenue bonds issued to % Rate Due 6.75 2003 April 1 S 29,850 S 29,850 finance the construction of pollution control 6.55 2003 October 1 27.315 27,315 facilities at certain plants. 6.00 2003 November 1 12,500 12,500 6.15 2003 December 1 20,000 20,000 (a) 2022 - February 10 - 5,000 Senior unsecured notes outstanding were as 7.75 2023 April 1 5,000 5,000 7.375 2023 October 1 20,250 20,250 follows: 7.10 2023 - November 1 12,000 12,000 December 31. 7.30 2024 April 1 10,000 10,000 2002 2001 Unamortized Discount (282) (371) (in thousands) Total 1135 633 5141, 4A % Rate Due 6.75 2004 July 1 $100,000 $100,000 (a) Redeemed on May 10, 2002. 7.00 2004 July 1 75,000 75,000 6.73 2004 November 1 48,000 48,000 6.24 2008 December 4 37,225 37,225 First mortgage bonds are secured by a first 7-3/8 2038 June 30 140,000 140,000 unamortized Discount (2.884) (39263) mortgage lien on electric utility plant. Certain Total S37,4 supplemental indentures to the first mortgage lien contain maintenance and replacement Notes payable to parent company were as provisions requiring the deposit of cash or follows: December 31. bonds with the trustee, or in lieu thereof, 2002 2001 (in thousainds) certification of unfunded property additions. % Rate Due 4.336% 2003 May 15 S 60,000 S 60,000 6.501% 2006 May 15 240.000 240.000 Installment purchase contracts have been Total Sa_,0 entered into in connection with the issuance of pollution control revenue bonds by Junior debentures outstanding were as governmental authorities as follows: follows: December 31. December 31. 2002 2001 2002 2001 (in thousands) (in thousands) % Rate Due % Rate Due (a) 2025 September 30 S - S 85,000 (a) 2027 March 31 - 50,000 Mason County, West unamortized Discount - (2.900) Virginia: Total 1 - si 5.45% 2016 December I S 50,000 S 50,000 (a) Redeemed on July 24, 2002 Marshall county, West Virginia: 5.45% 2014 July 1 50,000 50,000 5.90% 2022 April 1 35,000 35,000 At December 31, 2002 future annual long-6.85% 2022 Ohio Air Quality June 1 50,000 50,000 term debt payments are as follows: Development Amount 5.15% 2026 May 1 50,000 50,000 (in thousands) unamortized Discount (1.660) (1.765) 2003 S 149,665 Total 12I33,34 2004 223,000 2005 2006 240,000 Under the terms of the installment purchase 2007 contracts, OPCo is required to pay amounts Later Years 459.475 Total Principal Amount 1,072,140 unamortized Discount 4 826 Total 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. Combined Footnote Reference significant Accounting Policies Note 1 Extraordinary Items and cumulative Effect Note 2 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 Impairments 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 Supplementary Information Note 20 Leases Note 22 Lines of credit and sale of Receivables Note 23 unaudited Quarterly Financial Information Note 24 Related Party Transactions 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 Year Ended December 31. 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $ 793,647 $957,000 $956,398 $749,390 $780,159 operating Expenses 708.926 860.012 859.729 650.677 665.085 operating Income 84,721 96,988 96,669 98,713 115,074 Nonoperating Items, Net (3,239) 20 8,974 946 (91) Interest charges 40.422 39.249 38,980 38.151 38.074 Net Income 41,060 57,759 66,663 61,508 76,909 Preferred stock Dividend Requirements 213 213 212 212 213 Gain on Reacquired Preferred stock 1 Earnings Applicable to Common stock $ 40.848 LiZJ_.~ 1_0,A5I1 S-512% 96 $76-, December 31. 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $2,759,504 $2,695,099 $2,604,670 $2,459,705 $2,391,722 Accumulated Depreciation and Amortization 1.239,855 1.184.443 1.150.253 1,114.255 1.082.081 Net Electric Utility Plant $i,519,649 $1,510,656 $1.,454,417 $1 , 3A5,45Q Total Assets $1,76,69 24 $IAZ10 Common stock and Paid-in capital $ 337,246 $ 337,246 $ 337,246 $ 337,246 S 337,246 Accumulated other Comprehensive Income (Loss) (54,473) Retained Earnings 116.474 142.994 137,688 139.237 142. 941 Total Common shareholder's Equity S 399,247 $ 480s2A0 $ 474,934 S 476,483 cumulative Preferred Stock: Not subject to Mandatory Redemption $ 5. 27 Preferred securities of subsidiary Trust $LJ575000 S 75QQ0 Long-term Debt (a) $ 545,437 $ 451,129 $_384,064 Total capitalization and Liabilities ILi7Q $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) Changes in Operating Expenses is a public utility engaged in the generation, purchase, sale, transmission and distribution Increase (Decrease) From Previous Year of electric power to approximately 505,000 (dollars in millions) Amount % retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at Fuel S(215.3) (47) Purchased Power: wholesale to other utilities, municipalities and wholesale Electricity 23.3 96 rural electric cooperatives. AEP Affiliates 45.7 104 other operation (4.1) (3) Maintenance 1.9 4 Wholesale power marketing activities are Depreciation and Amortization 5.6 7 conducted on PSO s behalf byAEPSC. PSO, Taxes other Than along with the other AEP electric operating Income Taxes 2.1 7 Income Taxes (10.3) (30) subsidiaries, shares in AEP s electric power Total S(514) (18) transactions with other utility systems and N.M. = Not Meaningful power marketers. The decrease in Fuel expense in 2002 was Results of Operations primarily due to lower market prices for natural gas and fuel oil, and deferral of In 2002, Net Income decreased by $17 million underrecovered fuel costs due to the ICR or 29% primarily resulting from reduced adjustments through the fuel clause recovery wholesale margins and increased mechanism (see Note 6) and to the depreciation expense. amortization of previously overrecovered fuel costs. Changes in Operating Revenues The increase in Electricity Marketing Operating revenues decreased in 2002 as a Purchased Power expense in 2002 resulted result of reduced wholesale margins, a mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices. decline in fuel recovery revenue and decreases due to the interchange cost The increase in the AEP Affiliates Purchased reconstruction (ICR) adjustments (see Note Power expense in 2002 resulted mainly from 6). the ICR adjustments (see Note 6). Increase (Decrease) From Previous Year (dollars in millions) Other Operation expense decreased in 2002 Amount % primarily due to lower transmission expenses wholesale Electricity* S(149.7) (23) and decreased factoring expenses due to Energy Delivery* 13.6 5 reduced revenues. sales to AEP Affiliates t27.3) (74) Total operating Revenues S(163) (17) Maintenance expense increased, in 2002
- Reflects the allocation of certain transmission and distribution revenues largely as a result of increased expenses to included in bundled retail rates to energy repair damage to overhead lines caused by a delivery.
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 ZO21 2000 (in thousands) OPERATING REVENUES: wholesale Electricity $508,661 $658,352 $696,626 Energy Delivery 275,547 261,877 245,124 Sales to AEP Affiliates 9,439 36.771 14, 64 8 TOTAL OPERATING REVENUES 793,647 957.000 956. 398 OPERATING EXPENSES: Fuel 246,199 461,470 402,933 Purchased Power: wholesale Electricity 47,507 24,187 88,088 AEP Affiliates 89,454 43,758 60,788 other operation 133,538 137,678 121,697 Maintenance 48,060 46,188 45,858 Depreciation and Amortization 85,896 80,245 76,418 Taxes other Than Income Taxes 34,077 31,973 28,688 Income Taxes 24.195 34,513 35,259 TOTAL OPERATING EXPENSES 708.926 860.012 859.729 OPERATING INCOME 84,721 96,988 96,669 NONOPERATING INCOME 1,920 2,112 8,807 NONOPERATING EXPENSES 6,971 1,740 1,139 NONOPERATING INCOME TAX EXPENSE (CREDIT) (1,812) 352 (1,306) INTEREST CHARGES 40.422 39.249 38.980 NET INCOME 41,060 57,759 66,663 GAIN ON REACQUIRED PREFERRED STOCK 1 LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 213 213 212 EARNINGS APPLICABLE TO COMMON STOCK $ 40,848 ,$L5 $ 66AS5 Consolidated Statements of Comprehensive Income Year Ended December 31. 2002 2001 2000 (in thousands) NET INCOME $ 41,060 $57,759 $66,663 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (42) Minimum Pension Liability (54.431) COMPREHENSIVE INCOME (LOSS) $ (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 2000 (in thousands) BEGINNING OF PERIOD $142,994 $137,688 $139,237 NET INCOME 41,060 57,759 66,663 DEDUCTIONS: capital Stock Gains (1) Cash Dividends Declared: Common stock 67,368 52,240 68,000 Preferred stock 213 213 212 BALANCE AT END OF PERIOD $116,474 $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 $1,040,520 $1,034,711 Transmission 432,846 427,110 Distribution 990,947 972,806 General 206,747 203,572 Construction work in Progress 88.444 56.900 Total Electric utility Plant 2,759,504 2,695,099 Accumulated Depreciation and Amortization 1.239.855 1,184.443 NET ELECTRIC UTILITY PLANT 1.519.649 1,510,656 OTHER PROPERTY AND INVESTMENTS 41.020 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4.481 21. 354 CURRENT ASSETS: Cash and Cash Equivalents 16,774 5,795 Accounts Receivable: Customers 31,687 31,144 Affiliated companies 14,139 10,905 Allowance for uncollectible Accounts (84) (44) Fuel Inventory 19,973 21,559 Materials and supplies 37,375 36,785 under-recovered Fuel Costs 76,470 756 Energy Trading and Derivative Contracts 3,841 26,259 Prepayments and other 2.735 2.368 TOTAL CURRENT ASSETS 202.910 135. 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 December 31, 2002 2001 (in thousands) CAPTTALIZATION AND LIARILTTIFS CAPITALIZATION: Common Stock $15 Par value: Authorized shares: 11,000,000 Issued Shares: 10,482,000 outstanding Shares: 9,013,000 S 157,230 $ 157,230 Paid-in capital 180,016 180,016 Accumulated Other Comprehensive Income (Loss) (54,473) Retained Earnings 116,474 142.994 Total Common shareholder s Equity 399. 247 480.240 Cumulative Preferred stock Not subject to Mandatory Redemption 5,267 5,267 Pso-obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 445.437 345.129 TOTAL CAPITALIZATION 924.951 905.636 OTHER NONCURRENT LIABILITIES 54.761 7,263 CURRENT LIABILITIES: Long-term Debt Due within One Year 100,000 106,000 Advances from Affiliates 86,105 123,087 Accounts Payable General 61,169 72,759 Accounts Payable Affiliated Companies 78,076 40,857 Customer Deposits 21,789 21,041 Over-Recovered Fuel Costs 9,476 Taxes Accrued 6,854 18,150 Interest Accrued 6,979 7,298 Energy Trading and Derivative Contracts 3,260 31,718 other 24. 957 12,216 TOTAL CURRENT LIABILITIES 389.189 442.602 DEFERRED INCOME TAXES 341.396 296.877 DEFERRED INVESTMENT TAX CREDITS 32.201 33,992 REGULATORY LIABILITIES AND DEFERRED CREDITS 32.611 49.080 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,581 13.461 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $1,776,690 $1.748, 911. See Notes to Financia7 statements beginning on page L-1. 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 $ 41,060 $ 57,759 S 66,663 Adjustments to Reconcile Net Income to Net Cash from operating Activities: Depreciation and Amortization 85,896 80,245 76,418 Deferred Income Taxes 75,659 (17,751) 25,453 Deferred Investment Tax Credits (1,791) (1,791) (1,791) changes in Certain Assets and Liabilities: Accounts Receivable (net) (3,737) 21,405 (28,826) Fuel, Materials and supplies 996 (589) 677 other Property and Investments (419) (2,809) 7,994 Accounts Payable 25,629 (55,319) 89,330 Taxes Accrued (11,296) 16,491 (16,821) Fuel Recovery (85,190) 51,987 (36,798) Transmission Coordination Agreement settlement (15,063) changes in Other Assets 2,215 (9,120) 4,482 changes in Other Liabilities (6,928) 9.351 65.6193 Net Cash From Operating Activities 122.094 149,859 165.615 INVESTING ACTIVITIES: Construction Expenditures (124,520) (176,851) Proceeds from Sale of Property 963 other Items (359) Net cash used For Investing Activities (88.402) (124,879) (176.851) FINANCING ACTIVITIES: Issuance of Long-term Debt 187,850 105,625 Retirement of Long-term Debt (106,000) (20,000) (20,000) Change in Advances From Affiliates (net) (36,982) 41,967 1,951 Dividends Paid on Common Stock (67,368) (52,240) (68,000) Dividends Paid on cumulative Preferred stock (213) (213) (212) Net cash From (used For) Financing Activities (22,713) (30, 486) Net Increase (Decrease) in cash and cash Equivalents 10,979 (5,506) 8,128 cash and cash Equivalents January 1 11.301 3 .173 cash and cash Equivalents December 31 $1 5.795 6977 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) COMMON SHAREHOLDER S EQUITY $ 399.247 $480.240 PREFERRED STOCK: Cumulative $100 par value authorized shares 700,000, redeemable at the option of PSO upon 30 days notice. Call Price Shares December 31, Number of shares Redeemed outstanding Series 2002 Year Ended December 31, December 31. 2002 2002 2001 2000 Not subject to Mandatory Redemption: 4.00% $105.75 6 - 25 44,600 4,460 4,460 4.24% 103.19 - - - 8,069 807 807 5.267 5.267 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 75.000 75.000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 298,079 297,772 Installment Purchase Contracts 47,358 47,357 senior unsecured Notes 200,000 106,000 Less Portion Due Within one Year (100.000) (106. 000) Long-term Debt Excluding Portion Due within one Year 445.437 345.129 TOTAL CAPITALIZATION see Notes to Financial Statements beginning on page L-1. J-9
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Lona-term Debt First mortgage bonds outstanding were as Under the terms of the installment purchase follows: contracts, PSO is required to pay amounts December 31. sufficient to enable the payment of interest on 2002 2001 and the principal of (at stated maturities and (in thousands) % Rate Due upon mandatory redemptions) related 6.25 2003 April 1 S 35,000 S 35.000 pollution control revenue bonds issued to 7.25 2003 July 1 65,000 65,000 7.38 2004 December 1 50,000 50,000 finance the construction of pollution control 6.50 2005 7.38 2023 June 1 April 1 50,000 100,000 50,000 100, 000 facilities at certain plants. unamortized Discount (1.921) (2 228) S29Bs29 Senior unsecured notes outstanding were as First mortgage bonds are secured by a first follows: mortgage lien on electric utility plant. The December 31. indenture, as supplemented, relating to the 2002 2001 (in thousands) first mortgage bonds contains maintenance % Rate Due (a)i 2002 November 21 S - S106,000 and replacement provisions requiring the (b) 2032 December 31 200 000 - deposit of cash or bonds with the trustee, or in TOTAL 520 00M 16 0 lieu thereof, certification of unfunded property (a) A floating interest rate is determined additions. monthly. was $2.775%. The rate on December 31, 2001 (b) A fixed interest rate of 6.00% was the rate on December 31, 2002. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by At December 31, 2002, future annual long-governmental authorities as follows: term debt payments are as follows: December 31. Amount 2002 2001 (in thousands) (in thousands) Rat Due 2003 $100,000 Oklahoma Environmental 2004 50,000 Finance Authority (OEFA): 2005 50,000 5.90 2007 - December 1 S 1,000 S 1,000 2006 2007 1,000 Oklahoma Development Later Years 346. 360 Finance Authority (ODFA): Total Principal Amount 547, 360 4.875 2014 - June 1 33,700 33,700 unamortized Discount (1.923) Red River Authority Total 545 437 of Texas: 6.00 2020 June 1 Unamortized Discount 12,660 12,660 See Note 25 for discussion of the Trust (2) (3) Total i ,Al 3-58 547 357 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 Year Enided December 31, -- - - 2002 2001 2000 1999 1998 (in thousands) INCOME STATEMENTS DATA: operating Revenues $1,084,720 $1,101,326 $1,118,274 $ 971,527 $ 952,952 operating Expenses 942.251 955,119 989.996 824,465 802,274 operating Income 142,469 146,207 128,278 147,062 150,678 Nonoperating Items, Net (309) 741 3,851 (1,965) 2,451 Interest Charges 59,168 57, 581 59,457 _ 58,892 5,9135 Income Before Extraordinary Item 82,992 89,367 72,672 86,205 97,994 Extraordinary Loss (3,011) Net Income 82,992 89,367 72,672 83,194 97,994 Preferred stock Dividend Requirements 229 229 229 229 705 LOSS on Reacquired Preferred stock Earnings Applicable to Common stock $ 8J39& U$ 72,443 _$--- a33 December 31, 2002 2001 2000 1999 1998 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,596,174 $3,460,764 $3,319,024 $3,231,431 $3,157,911 Accumulated Depreciation and Amortization 1. 697. 338 1,550,618 1,457,005 1.384.242 1.317.057 Net Electric Utility Plant -$i Q0,146 $1&862019 -£2 IQ-85A'25 Total Assets $2 2SL67I5 16762:
,2
$L380,616 $ 380,663 Common stock and Paid-in capital $ 380,663 $ 380,663 $ 380,663 $ 380,663 $ 380,663 Accumulated other Comprehensive Income (Loss) (53,683)
Retained Earnings 334,789 308,915 293,989 283, 546 296, 581 Total Common shareholder's Equity S$_&6W5i8 $-6!A.-5i2 S-664,ZO0 $_677L244 Preferred stock $ 4=,=z2 .11 1 LQ1 $ 4,70-1~ 2Q Trust Preferred securities $__11O0,Q $ 110,000 A114QQ00 £_lUXlQQQ Long-term Debt (a) _$__M -t645 S& 6A45,963 A15& Total capitalization and Liabilities £$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 Operating Revenues decreased 2% for 2002 (SWEPCo) is a public utility engaged in the primarily due to decreased fuel revenues generation, purchase, sale, transmission and offset in part by the addition of the Dolet Hills distribution of electric power to approximately mining operation ($12.6 million) and the 437,000 retail customers in northeastern positive impact of the interchange cost Texas, northwestern Louisiana and western reconstruction (ICR) adjustments (see Note Arkansas. SWEPCo also sells electric power 6). at wholesale to other utilities, municipalities and rural electric cooperatives. In 2001, Operating Revenues decreased $17 million or 2% resulting from unfavorable Wholesale power marketing activities are wholesale marketing and trading conditions. conducted on SWEPCo s behalf by AEPSC. SWEPCo, along with the other AEP electric Changes in Operating Expenses operating subsidiaries, shares in AEP s Increase (Decrease) electric power transactions with other utility From Previous Year systems and power marketers. (dollars in millions) 2002 2001 Amount % Amount X Results of Operations Fuel S(69) (15) S(41) (8) Purchased Power: In 2002, Net Income decreased $6.4 million or wholesale 7% primarily resulting from reduced margins. Electricity 26 143 (40) (69) AEP In 2001, Net Income increased $16.7 million Affiliates 26 165 2 19 or 23% resulting primarily from the favorable other operation 18 10 12 7 impact of our sharing in AEP s power Maintenance (8) (10) - (1) marketing activities for a full year. Depreciation and Amortization 3 3 15 14 Taxes other Changes in Operating Revenues Than Income Taxes (1) (1) 2 4 Income Taxes (20) 16 60 Increase (Decrease) Total (8) (1) £LI) (4) From Previous Year (dollars in millions 2002 2001 Fuel expense decreased in 2002 due to a Amount % Amount % reduction in MWH generated and a decrease wholesale in the cost of fuel, primarily natural gas. Electricity* $(25) (4) S(21) (3) Energy Delivery* 15 5 (12) (3) Sales to AEP Fuel expense decreased in 2001 from lower Affiliates .7) (9) 16 26 natural gas prices and a mild summer Total operating resulting in a reduction in generation. Revenues £-1Z) (2) ILU) (2)
- Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
K-2
L. In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In2001, 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 $ 664,185 $ 689,085 $ 710,200 Energy Delivery 348,236 333,004 344,950 Sales to AEP Affiliates 72,299 79,237 63,124 TOTAL OPERATING REVENUES 1.084,720 1.101.326 1.118.274 OPERATING EXPENSES: Fuel 388,334 457,613 498,805 Purchased Power: wholesale Electricity 44,119 18,164 58,518 AEP Affiliates 42,022 15,858 13,338 other operation 189,024 171,314 159,459 Maintenance 66,855 74,677 75,123 Depreciation and Amortization 122,969 119,543 104,679 Taxes other Than Income Taxes 55,232 55,834 53,830 Income Taxes 33,696 42,116 26,244 TOTAL OPERATING EXPENSES 942.251 955.119 989, 996 OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 4,512 5,487 NONOPERATING EXPENSES 1,797 3,229 3,112 NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,772 542 (1,476) INTEREST CHARGES 59.168 57, 581 59.457 NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229 EARNINGS APPLICABLE TO COMMON STOCK S 82.e763 S 89,138 S 72.443 Consolidated Statements of Comprehensive Income Year Ended December 31. 2002 2001 2000 (in thousands)
--- --- $72,672 NET INCOME $82,992 $89,36 7 OTHER COMPREHENSIVE INCOME (LOSS):
cash Flow Power Hedges (48) - Minimum Pension Liability (53.635) - COMPREHENSIVE INCOME "24.309 S___36 $72 f92 The common stock of SWEPco is owned by a who77y owned subsidiary of AEP. See Notes to Financial statements beginning on page L-1. 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 $308,915 $293,989 $283,546 NET INCOME 82,992 89,367 72,672 DEDUCTIONS: cash Dividends Declared: Common stock 56,889 74,212 62,000 Preferred stock 229 229 229 BALANCE AT END OF PERIOD $ 3C&4915 $s91I9&9 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 $1,503,722 $1,429,356 Transmission 575,003 538,749 Distribution 1,063,564 1,042,523 General 378,130 376,016 Construction work in Progress 75,755 74.120 Total Electric utility Plant 3,596,174 3,460,764 Accumulated Depreciation and Amortization 1.697. 338 1.550.618 NET ELECTRIC UTILITY PLANT 1.898.836 1.910,146 OTHER PROPERTY AND INVESTMENTS 5,978 43.000 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 5,119 24,508 CURRENT ASSETS: Cash and cash Equivalents 2,069 5,415 Accounts Receivable: Customers 62,359 43,133 Affiliated Companies 19,253 12,069 Allowance for uncollectible Accounts (2,128) (89) Fuel Inventory 61,741 52,212 Materials and supplies 33,539 32,527 Under-recovered Fuel Costs 2,865 8,839 Energy Trading and Derivative Contracts 4,388 30,139 Prepayments and other 17,851 18,716 TOTAL CURRENT ASSETS 201.937 202.961 REGULATORY ASSETS 49,233 52. 308 DEFERRED CHARGES 47. 572 67, 753 TOTAL ASSETS $2,20,65 $2,300,676 see Notes to Financia7 statements beginning on page L-1. K-6
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES December 31. 2002 2001 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stock $18 Par value: Authorized 7,600,000 Shares Outstanding 7,536,640 shares $ 135,660 $ 135,660 Paid-in capital 245,003 245,003 Accumulated other Comprehensive Income (Loss) (53,683) Retained Earnings 334,789 308.915 Total Common shareholder s Equity 661,769 689,578 Preferred stock 4,701 4,701 SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo 110,000 110,000 Long-term Debt 637.853 494,688 TOTAL CAPITALIZATION 1.414.323 1. 298.967 OTHER NONCURRENT LIABILITIES 78.494 40,109 CURRENT LIABILITIES: Long-term Debt Due within One Year 55,595 150, 595 Advances from Affiliates, net 23,239 117,367 Accounts Payable General 62,139 71,810 Accounts Payable Affiliated Comp;ani es 58,773 37,469 Customer Deposits 20,110 19,880 Taxes Accrued 19,081 36,522 Interest Accrued 17,051 13,027 Energy Trading and Derivative Cont racts 3,724 36,297 over-recovered Fuel 17,226 5,487 other 34, 565 26,074 TOTAL CURRENT LIABILITIES 311.503 514.,528 DEFERRED INCOME TAXES 341.064 369.78 DEFERRED INVESTMENT TAX CREDITS 44,190 48.714 REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 13.,127 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1.806 15,45S0 COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $2,208,675 2LINJ7U See Notes to Financia7 statements beginning on page L-1. 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 $ 82,992 $ 89,367 S 72,672 Adjustments to Reconcile Net Income to Net cash Flows From Operating Activities: Depreciation and Amortization 122,969 119,543 104,679 Deferred Income Taxes (3,134) (31,396) 14,653 Deferred Investment Tax credits (4,524) (4,453) (4,482) Mark-to-Market Energy Trading and Derivative Contracts (1,151) (10,695) 7,795 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (24,371) (11,447) (1,254) Fuel, Materials and supplies (10,541) (19,578) 22,103 Accounts Payable 11,633 (34,489) 43,962 Taxes Accrued (17,441) 25,298 (13,150) Transmission coordination Agreement Settlement (24,406) Fuel Recovery 17,713 34,423 (38,357) change in other Assets 24,257 1,323 54,414 change in other Liabilities 12.16 11, 714 (37.001) Net cash Flows From Operating Activities 210.563 169.610 201.628 INVESTING ACTIVITIES: Construction Expenditures (111,775) (111,725) (120,671) Purchase of Dolet Hills Mining operations (85,716) other 1.134 (411) 446 Net cash Flows used For - Investing Activities (110.641) (197.852) (120.225) FINANCING ACTIVITIES: Issuance of Long-term Debt 198,573 149,360 Redemption of Preferred stock (1) Retirement of Long-term Debt (150,595) (595) (45,595) Change in Advances From Affiliates (net) (94,128) 106,786 (124,074) Dividends Paid on Common Stock (56,889) (74,212) (62,000) Dividends Paid on Cumulative Preferred Stock (229) (229) (229) Net cash Flows From (used For) Financing Activities (103,268) 31.750 (82.5 39) Net Increase (Decrease) in cash and cash Equivalents (3,346) 3,508 (1,136) Cash and Cash Equivalents January 1 5.415 1.907 3.043 cash and cash Equivalents December 31 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) COMMON SHAREHOLDER S EQUITY S 661.769 $ 689.578 PREFERRED STOCK: $100 par value authorized shares 1,860,000 call Price Shares December 31, Number of shares Redeemed Outstanding series 2002 Year Ended December 31E December 31. 2002 2002 2001 2000 Not subject to Mandatory Redemption: 4.28% $103.90 - - - 7,386 740 740 4.65% $102.75 - - - 1,907 190 190 5.00% $109.00 - - 12 37,715 3.771 3. 771 4.701 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 110.000 110.000 LONG-TERM DEBT (See schedule of Long-term Debt): First Mortgage Bonds 315,420 315,449 Installment Purchase Contracts 179,183 179,834S Senior Unsecured Notes 198,845 150,000 Less Portion Due within one Year (55.595) (150. 595) Long-term Debt Excluding Portion Due within one Year 637. 853 494.688 TOTAL CAPITALIZATION 11_41Mv23 See Notes to Financial statements beginning on page L-1. K-9
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as Under the terms of the installment purchase follows: contracts, SWEPCo is required to pay December 31, 2002 2001 amounts sufficient to enable the payment of (in thousands) interest on and the principal of (at stated % Rate Due 6-5/8 2003 February 1 S 55,000 S 55,000 maturities and upon mandatory redemptions) 7-3/4 2004 June 1 40,000 40,000 related pollution control revenue bonds issued 6.20 2006 November 1 5,505 5,650 6.20 2006 November 1 1,000 1,000 to finance the construction of pollution control 7.00 2007 7-1/4 2023 Se tember I Juqy 1 90,000 45,000 90,000 45,000 facilities at certain plants. 6-7/8 2025 October 1 80 000 80,000 unamortized Discount (1.085) (1.201) Senior unsecured notes outstanding were as S315-420 follows: First mortgage bonds are secured by a first December 31, mortgage lien on electric utility plant. The 2002 2001 indenture, as supplemented, relating to the % Rate Due Otiw thousandcs-) first mortgage bonds contains maintenance 4.50 2005 July 1 S200,000 S - (a) 2002 March 1 - 150,000 and replacement provisions requiring the Unamortized Discount _. 198;85 5) 0OO deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property (a)A floating interest rate is determined additions. monthly. The rate on December 31, 2001 was 2.311%. Installment purchase contracts have been At December 31, 2002 future annual long-entered into in connection with the issuance term debt payments are as follows: of pollution control revenue bonds by Amount governmental authorities as follows: (in thousands) 2003 S 55,595 December 31, 2004 52,885 2002 2001 2005 200,595 (in thousands) 2006 6,520 % Rate Due 2007 90,450 DeSoto County: Later Years 287.695 Total Principal Amount 693,740 7.60 2019 January 1 S 53,500 $ 53,500 unamortized Discount (292) Total S69344 Sabine: 6.10 2018 April 1 81,700 81,700 See Note 25 for discussion of Trust Preferred Titus County: Securities issued by awholly-owned statutory 6.90 2004 - November 1 12,290 12,290 business trust of SWEPCo. 6.00 2008 - January 1 12,620 13,070 8.20 2011 August 1 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. combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Goodwill and other Intangible Assets Note 3 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 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 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 AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 19. Basic and Diluted Earnings Per Share AEP
- 20. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo
- 21. Power and Distribution Projects AEP
- 22. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 23. Lines of Credit and Sale of Receivables AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 24. Unaudited Quarterly Financial Information AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 25. Trust Preferred Securities AEP, PSO, SWEPCo, TCC
- 26. Minority Interest in Finance Subsidiary AEP
- 27. Equity Units AEP
- 28. Jointly Owned Electric Utility Plant
- CSPCo, PSO, SWEPCo, TCC, TNC
- 29. Related Party Transactions AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
- 30. Subsequent Events (Unaudited) AEP L-2
- 1. Significant Accounting Policies: operations and transmission rates and the state commissions regulate retail rates. The prices Business Operations AEP s (the Company s) charged by foreign subsidiaries located in China, principal business conducted by its eleven Mexico and Brazil are regulated bythe authorities domestic electric utility operating companies is the of that country and are generally subject to price generation, transmission and distribution of controls.
electric power. Nine of AEP s eleven domestic electric utility operating companies, APCo, Principles of Consolidation AEP s consolidated CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, financial statements include AEP Co., Inc. and its TCC, TNC, are SEC registrants. AEGCo is a wholly-owned and majority-owned subsidiaries domestic generating company wholly-owned by consolidated with their wholly-owned or AEP that is an SEC registrant. These companies substantially controlled subsidiaries. The are subject to regulation by the FERC under the consolidated financial statements for APCo, Federal Power Act and follow the Uniform System CSPCo, I&M, PSO, SWEPCo and TCC include of Accounts prescribed by FERC. They are the registrant and its wholly-owned subsidiaries. subject to further regulation with regard to rates Significant intercompany items are eliminated in and other matters by state regulatory consolidation. Equity investments not commissions. substantially controlled that are 50% or less owned are accounted for using the equity method AEP also engages in wholesale marketing and with their equity earnings included in Other trading of electricity, natural gas and to a lesser Income forAEP and nonoperating income for the extent, other commodities in the United States registrant subsidiaries. and Europe. In addition,theCompanysdomestic operations include non-regulated independent Basis ofAccounting - As the owner of cost-based power and cogeneration facilities, coal mining and rate-regulated electric public utility companies, intra-state midstream natural gas operations in AEP Co., Inc.'s consolidated financial statements Louisiana and Texas. reflect the actions of regulators that result in the recognition of revenues and expenses in different International operations include supply of time periods than enterprises that are not rate-electricity and other non-regulated power regulated. In accordance with SFAS 71, generation projects in the United Kingdom, and to "Accounting for the Effects of Certain Types of a lesser extent in Mexico, Australia, China and the Regulation, regulatory assets (deferred Pacific Rim region. These operations are either expenses) and regulatory liabilities (future wholly-owned or partially-owned by various AEP revenue reductions or refunds) are recorded to subsidiaries. We also maintained operations in reflect the economic effects of regulation by Brazil through the fourth quarter of 2002. See matching expenses with their recovery through Note 13 for discussion of impaired investments regulated revenues. Application of SFAS 71 for and assets held for sale. the generation portion of the business was discontinued as follows: in Ohio by OPCo and The Company also operates domestic barging CSPCo in September 2000, in Virginia and West operations, provides various energy related Virginia byAPCo in June 2000, in Texas byTCC, services and furnishes communications related TNC, and SWEPCo in September 1999 and in services domestically. See Note 13 for further Arkansas by SWEPCo in September 1999. See discussion of changes in our communications Note 8, "Customer Choice and Industry related business and other business operations Restructuring for additional information. announced in 2002. Use of Estimates - The preparation of these Rate Regulation AEP is subject to regulation by financial statements in conformity with generally the SEC under the PUHCA. The rates charged accepted accounting principles necessarily by the domestic utility subsidiaries are approved includes the use of estimates and assumptions by by the FERC and the state utility commissions. management. Actual results could differ from The FERC regulates wholesale electricity those estimates. L-3
Property, Plant and Equipment Domestic Depreciation, Depletion and Amortization - electric utility property, plant and equipment are Depreciation of property, plant and equipment is stated at original cost of the acquirer. Property, provided on a straight-line basis over the plant and equipment of the non-regulated estimated useful lives of property, otherthan coal-operations and other investments are stated at mining property, and is calculated largely through their fair market value at acquisition plus the the use of composite rates by functional class as original cost of property acquired or constructed follows: since the acquisition, less disposals. Additions, Annual Composite major replacements and betterments are added to Functional Class Depreciation Rates of ProDertv Ranges the plant accounts. For cost-based rate-regulated 2002 operations, retirements from the plant accounts Production: Steam-Nuclear 2.5% to 3.4% and associated removal costs, net of salvage, are Steam-Fossil -Fi red 2.6% to 4.5% deducted from accumulated depreciation. The Hydroelectric- conventional and Pumped Storage 1.9% to 3.4% costs of labor, materials and overhead incurred to Transmission 1.7% to 3.0% operate and maintain plant are included in Distribution 3.3% to 4.2% other 1.8% to 9.9% operating expenses. Plants are tested for Annual Composite impairment as required under SFAS 144. See Functional class Depreciation Rates Note 13. of ProDerty Ranges 2001 Production: Allowance for Funds Used During Construction Steam-Nuclear 2.5% to 3.4% Steam-Fossil-Fired 2.5% to 4.5% (AFUDC) and Interest Capitalization -AFUDC is a Hydroelectric- conventional and Pumped Storage 1.9% to 3.4% noncash, nonoperating income item that is Transmission 1.7% to 3.1% capitalized and recovered through depreciation Distribution other 2.7% 1.8% to 4.2% to 15.0% over the service life of domestic regulated electric utility plant. It represents the estimated cost of Annual Composite Functional class Depreciation Rates borrowed and equity funds used to finance of ProDerty Ranges 2000 construction projects. The amounts of AFUDC for Production: 2002, 2001 and 2000 were not significant. Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 2.3% to 4.5% Effective with the discontinuance of SFAS 71 Hydroelectric- conventional regulatory accounting for domestic generating and Pumped Storage Transmission 1.9% 1.7% to to 3.4% 3.1% assets in Arkansas, Ohio, Texas, Virginia, West Distribution 3.3% to 4.2% Virginia and other non-regulated operations, other 2.5% to 7.3% 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. 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 3.5% 2.8% APCo 3.4 2.9 2.2 3.3 3.1 CSPco 3.2 2.3 3.6 3.2 I&M 3.4 4.5 3.4 1.9 4.2 3.8 KPCo 3.8 1.7 3.5 2.5 OPCo 3.4 2. 7 2.3 4.0 2.7 PSO 2.7 2.3 3.4 6.3 SWEPCo 3.4 2.7 3.6 4.7 TCC 2.5 2.6 1.9 2.3 3.5 4.0 TNC 2.8 3.1 3.3 6.8 Depreciation, depletion and amortization of coal- as described in the New Accounting mining assets is provided over each asset's Pronouncements section of Note 1, natural gas estimated useful life or the estimated life of the inventories held in connection with trading mine, whichever is shorter, and is calculated operations at October 25, 2002 continued to be using the straight-line method for mining carried atfairvalue until December31,2002, and structures and equipment. The units-of- inventory purchased from October 26 through production method is used to amortize coal rights December 31, 2002 was carried at the lower of and mine development costs based on estimated cost or market. Effective January 1, 2003, all recoverable tonnages. These costs are included natural gas inventories held in connection with in the cost of coal charged to fuel expense for trading operations will be adjusted to the historical coal used by utility operations. Current average cost basis and carried at the lower of cost or amortization rates are $0.32 per ton in 2002, market. We estimate the adjustment in January $3.46 per ton in 2001 and $5.07 per ton in 2000. 2003 will decrease the value of natural gas In 2001, an AEP subsidiary sold coal mines in inventories held in connection with trading Ohio and West Virginia. See Note 12, operations by approximately $39 million. This Acquisitions, Dispositions and Discontinued change will be accounted for as a cumulative Operations for further discussion of the changes effect of a change in accounting principle. in our coal investments leading to the decline in amortization rates in 2002. Accounts Receivable AEP Credit, Inc. factors accounts receivable for certain of the domestic Cash and Cash Equivalents - Cash and cash utility subsidiaries and, until the first quarter of equivalents include temporary cash investments 2002, factored accounts receivable for certain with original maturities of three months or less. non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into asale of receivables Inventory Except for PSO, TCC and TNC, the agreementwith a group of banks and commercial regulated domestic utility companies value fossil paper conduits. This transaction constitutes a fuel inventories using a weighted average cost sale of receivables in accordance with SFAS 140, method. PSO, TCC and TNC, utilize the LIFO allowing the receivables to be taken off of the method to value fossil fuel inventories. For those companys balance sheet. See Note 23 for domestic utilities whose generation is further details. unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories Foreign Currency Translation - The financial are also carried at the lower of cost or market. statements of subsidiaries outside the U.S. which Materials and supplies inventories are carried at are included in AEP s consolidated financial average cost. statements are measured using the local currency as the functional currency and translated into U.S. Non-trading gas inventory is carried at the lower dollars in accordance with SFAS 52 "Foreign of cost or market. In compliance with EITF 02-03 Currency Translation . Assets and liabilities are L-5
translated to U.S. dollars at year-end rates of financial statements of AEP and the financial exchange and revenues and expenses are statements of electric operating subsidiary translated at monthly average exchange rates companies with cost-based rate-regulated throughout the year. Currency translation gain operations (I&M, KPCo, PSO, and a portion of and loss adjustments are recorded in APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), shareholders' equity as Accumulated Other reflect the actions of regulators that can result in Comprehensive Income (Loss). The non-cash the recognition of revenues and expenses in impact of the changes in exchange rates on cash, different time periods than enterprises that are not resulting from the translation of items at different rate regulated. In accordance with SFAS 71, exchange rates, is shown on AEP s Consolidated regulatory assets (deferred expenses to be Statements of Cash Flows in Effect of Exchange recovered in the future) and regulatory liabilities Rate Changes on Cash. Actual currency (deferred future revenue reductions or refunds) transaction gains and losses are recorded in are recorded to reflect the economic effects of income. regulation by matching expenses with their recoverythrough regulated revenues in the same Deferred Fuel Costs - The cost of fuel consumed accounting period and by matching income with is charged to expense when the fuel is burned. its passage to customers through regulated Where applicable under governing state revenues in the same accounting period. regulatory commission retail rate orders, fuel cost Regulatory liabilities are also recorded to provide over or under-recoveries are deferred as currently for refunds to customers that have not regulatory liabilities or regulatory assets in yet been made. accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to When regulatory assets are probable of recovery customers in later months with the regulators through regulated rates, we record them as review and approval. The amount of deferred fuel assets on the balance sheet. We test for costs under fuel clauses forAEP was $143 million probability of recovery whenever new events at December 31, 2002 and $139 million at occur, for example a regulatory commission order December 31, 2001. See Note 7 "Effects of or passage of new legislation. If we determine Regulation . that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a We are protected from fuel cost changes in charge against net income. A write off of Kentucky for KPCo, the SPP area of Texas, regulatory assets may also reduce future cash Louisiana and Arkansas for SWEPCo, Oklahoma flows since there may be no recovery through for PSO and Virginia for APCo. Where fuel regulated rates. clauses have been eliminated due to the transition to market pricing, (Ohio effective Traditional Electricity Supply and Deliverv January 1, 2001 and in the Texas ERCOT area Activities - Revenues are recognized on the effective January 1, 2002) changes in fuel costs accrual or settlement basis for normal retail and impact earnings. In other state jurisdictions, wholesale electricity supply sales and electricity (Indiana, Michigan and West Virginia) where fuel transmission and distribution delivery services. clauses have been frozen or suspended for a The revenues are recognized in our income period of years, fuel cost changes also impact statement when the energy is delivered to the earnings. This is also true for certain of AEP s customer and include unbilled as well as billed Independent Power Producer generating units amounts. In general, expenses are recorded that do not have long-term contracts for their fuel when purchased electricity is received and when supply. See Note 6, "Rate Matters and Note 8, expenses are incurred. "Customer Choice and Industry Restructuring for further information about fuel recovery. Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas Revenue Recognition - pipeline and storage services when gas is delivered to contractual meter points or when Regulatory Accountinq - The consolidated services are provided. Transportation and L-6
storage revenues also include the accrual of area, the total gain or loss realized in cash for earned, but unbilled andlor not yet metered gas. sales and the cost of purchased energy are included in revenues on a net basis. Prior to Substantially all of the forward gas purchase and settlement, changes in the fair value of physical sale contracts, excluding wellhead purchases of forward sale and purchase contracts in AEP s natural gas, swaps and options for the domestic traditional marketing area are deferred as pipeline operations, qualify as derivative financial regulatory liabilities (gains) or regulatory assets instruments as defined by SFAS 133. (losses). For contracts with delivery points Accordingly, net gains and losses resulting from outside of AEP s traditional marketing area only revaluation of these contacts to fair value during the difference between the accumulated the period are recognized currently in the results unrealized net gains or losses recorded in prior of operations, appropriately discounted and net of periods and the cash proceeds is recognized in applicable credit and liquidity reserves. the income statement as nonoperating income. Prior to settlement, changes in the fair value of Energy Marketinq and Trading Transactions physical forward sale and purchase contracts with In 2000, 2001 and throughout the majority of delivery points outside of AEP s traditional 2002, AEP engaged in wholesale electricity, marketing area are included in nonoperating natural gas and other commodity marketing and income on a net basis. Unrealized mark-to-trading transactions (trading activities). Trading market gains and losses are included in the activities involve the purchase and sale of energy Balance Sheet as energy trading contract assets under forward contracts at fixed and variable or liabilities as appropriate. prices and the trading of financial energy contracts which includes exchange futures and For APCo, CSPCo and OPCo, depending on options and over-the-counter options and swaps. whether the delivery point for the electricity is in We use the mark-to-market method of accounting AEP s traditional marketing area or not for trading activities as required by EITF Issue No. determines where the contract is reported in the 98-10, "Accounting for Contracts Involved in income statement. Physical forward trading sale Energy Trading and Risk Management Activities and purchase contracts with delivery points in (EITF 98-10). Under the mark-to-market method AEP s traditional marketing area are included in of accounting, gains and losses from settlements revenues on a net basis. Prior to settlement, of forward trading contracts are recorded net in changes in the fair value of physical forward sale revenues. For energy contracts not yet settled, and purchase contracts in AEP s traditional whether physical or financial, changes in fair marketing area are also included in revenues on a value are recorded net in revenues as unrealized net basis. Physical forward sale and purchase gains and losses from mark-to-marketvaluations. contracts for delivery outside of AEP s traditional When positions are settled and gains and losses marketing area are included in nonoperating are realized, the previously recorded unrealized income when the contract settles. Prior to gains and losses from mark-to-market valuations settlement, changes in the fair value of physical are reversed. In October 2002, management forward sale and purchase contracts with delivery announced plans to focus on wholesale markets points outside of AEP s traditional marketing area around owned assets. are included in nonoperating income on a net basis. All of the registrant subsidiaries except AEGCo participate in AEP s wholesale marketing and The trading of energy options, futures and swaps, trading of electricity. For l&M, KPCo, PSO and a represents financial transactions with unrealized portion of TNC and SWEPCo, when the contract gains and losses from changes in fair values settles the total gain or loss is realized in cash. reported net in AEP s revenues until the contracts Where this amount is recorded on the income settle. When these contracts settle, the net statement depends on whether the contract s proceeds are recorded in revenues and reverse delivery points are within or outside of AEP s the prior cumulative unrealized net gain or loss. traditional marketing area. For contracts with APCo, CSPCo, OPCo, I&M and KPCo also have delivery points in AEP s traditional marketing financial transactions, but record the unrealized L-7
gains and losses, as well as the net proceeds the cost of debt to be issued. These anticipatory upon settlement, in nonoperating income. debt instruments are entered into in order to manage the change in interest rates between the The fair values of open short-term trading time a debt offering is initiated and the issuance contracts are based on exchange prices and of the debt (usually a period of 60 days). Gains or broker quotes. Open long-term trading contracts losses from these transactions are deferred and are marked-to-market based mainly on AEP- amortized over the life of the debt issuance with developed valuation models. The models are the amortization included in interest charges. derived from internally assessed market prices There were no such forward contracts with the exception of the NYMEX gas curve, outstanding at December 31, 2002 or 2001. See where we use daily settled prices. All fair value Note 17 'Risk Management, Financial amounts are net of appropriate valuation Instruments and Derivatives for further adjustments for items such as discounting, discussion of the accounting for risk management liquidity and credit quality. Such valuation transactions. adjustments provide for a better approximation of fair value. The use of these models to fair value Levelization of Nuclear Refueling Outage Costs - open trading contracts has inherent risks relating In order to match costs with regulated revenues, to the underlying assumptions employed by such incremental operation and maintenance costs models. Independent controls are in place to associated with periodic refueling outages at evaluate the reasonableness of the price curve I&M s Cook Plant are deferred and amortized over models. Significant adverse or favorable effects the period beginning with the commencement of on future results of operations and cash flows an outage and 'ending with the beginning of the could occur if market prices, at the time of next outage. settlement, do not correlate with AEP-developed price models. Maintenance Costs Maintenance costs are expensed as incurred except where SFAS 71 As explained above, the effect on AEP s requires the recordation of a regulatory asset to Consolidated Statements of Operations of match the expensing of maintenance costs with marking to market open electricity trading their recovery in cost-based regulated revenues. contracts in AEP s regulated jurisdictions is See below for an explanation of costs deferred in deferred as regulatory assets (losses) or liabilities connection with an extended outage at l&M s (gains) since these transactions are included in Cook Plant. cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market Amortization of Cook Plant Deferred Restart gains and losses from trading activities whether Costs - Pursuant to settlement agreements deferred or recognized in revenues are part of approved by the IURC and the MPSC to resolve Energy Trading and Derivative Contracts assets all issues related to an extended outage of the or liabilities as appropriate. Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs Construction Projects for Outside Parties during 1999. The deferred amount is being Certain AEP entities engage in construction amortized to expense on a straight-line basis over projects for outside parties that are accounted for five years from January 1, 1999 to December 31, on the percentage-of-completion method of 2003. I&M amortized $40 million each year 1999 revenue recognition. This method recognizes through 2002 leaving $40 million as an SFAS 71 revenue in proportion to costs incurred compared regulatory asset at December 31, 2002 on the to total estimated costs. Consolidated Balance Sheets of AEP and l&M. Debt InstrumentHedging and RelatedActivities Other Income and Other Expenses Other In order to mitigate the risks of market price and Income includes non-operational revenue interest rate fluctuations, AEP, APCo, CSPCo, including area business development and river I&M, KPCo and OPCo enter into contracts to transportation, equity earnings of non-manage the exposure to unfavorable changes in consolidated subsidiaries, gains on dispositions of L-8
property, interest and dividends, an allowance for amortized over the life of the regulated plant equity funds used during construction (explained investment. above) and miscellaneous income. Other Expenses includes non-operational expense Excise Taxes AEP and its subsidiary including area business development and river registrants, as an agent for a state or local transportation, losses on dispositions of property, government, collect from customers certain miscellaneous amortization, donations and excise taxes levied by the state or local various other non-operating and miscellaneous government upon the customer. These taxes are expenses. not recorded as revenue or expense, but only as a pass-through billing to the customer to be AEP Consolidated other Income and Deductions remitted to the government entity. Excise tax December 31, collections and payments related to taxes 2002 2001 2000 imposed upon the customer are not presented in (in millions) OTHER INCOME: the income statement. Equity Earnings S 104 S 123 $ 22 Non-operational Revenue 187 123 71 Interest and Debt and Preferred Stock Gains and losses Miscellaneous Income 25 16 2 from the reacquisition of debt used to finance Gain on sale of Frontera Gain on sale of Retail 73
- - domestic regulated electric utility plant are Electric Provider 129 - - generally deferred and amortized over the Total other Income S 45 S- ___ remaining term of the reacquired debt in accordance with their rate-making treatment. If OTHER EXPENSES: debt associated with the regulated business is Property Taxes and Miscellaneous Expenses S 142 S 68 5 28 refinanced, the reacquisition costs attributable to Non-operational Expenses 179 56 49 the portions of the business that are subject to Fiber optic and - 49 - cost based regulatory accounting under SFAS 71 Datapult Exit Costs Provision for Loss - are generally deferred and amortized over the Airplane - 14 term of the replacement debt commensurate with Total other Expenses S1321 s1&z Lz their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to Income Taxes - The AEEP System follows the SFAS 71 are reported as a Loss on Reacquired liability method of accoun ting for income taxes as Debt, an extraordinary item on the Consolidated prescribed by SFAS 109, lAccounting for Income Statements of Operations of AEP and TCC. See Taxes. Under the liat iility method, deferred discussion of SFAS 145 in New Accounting income taxes are provi'ded for all temporary Pronouncements section of this note for new differences between the Ibook cost and tax basis treatment effective in 2003.
of assets and liabilities which will result in a future tax consequence. Where the flow-through Debt discount or premium and debt issuance method of accounting for temporary differences is expenses are deferred and amortized utilizing the reflected in regulated revenues (that is, deferred effective interest rate method over the term of the taxes are not included in the cost of service for related debt. The amortization expense is determining regulated rates for electricity), included in interest charges. deferred income taxes are recorded and related regulatory assets and liabilities are established in Where rates are regulated, redemption premiums accordance with SFAS 71 to match the regulated paid to reacquire preferred stock of the domestic revenues and tax expense. utility subsidiaries are included in paid-in capital and amortized to retained earnings Investment Tax Credits - Investment tax credits commensurate with their recovery in rates. The have been accounted for under the flow-through excess of par value over costs of preferred stock method except where regulatory commissions reacquired is credited to paid-in capital and have reflected investment tax credits in the rate- amortized to retained earnings consistentwith the making process on a deferral basis. Investment timing of its inclusion in rates in accordance with tax credits that have been deferred are being SFAS 71. L-9
Goodwill and Intangible Assets In June 2001, Nuclear Trust Funds Nuclear decommissioning the FASB issued SFAS 141, Business and spent nuclear fuel trust funds represent funds Combinations, and SFAS 142, Goodwill and that regulatory commissions have allowed us to Other Intangible Assets, affecting AEP and collect through rates to fund future SWEPCo. decommissioning and spent fuel disposal liabilities. By rules or orders, the state SFAS 141 requires that the purchase method of jurisdictional commissions (Indiana, Michigan and accounting be used for all business combinations Texas) and the FERC established investment initiated after June 30,2001 and established new limitations and general risk management standards for the recognition of certain identifiable guidelines to protect their ratepayers funds and to intangible assets, separate from goodwill. We allow those funds to earn a reasonable return. In adopted the provisions of SFAS 141 effective July general, limitations include: 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note . Acceptable investments (rated investment 3 for further discussion of our components of grade or above) goodwill and intangible assets.
- Maximum percentage invested in a specific type of investment SFAS 142 requires that goodwill and intangible
- Prohibition of investment in obligations of the assets with finite useful lives no longer be applicable company or its affiliates.
amortized, but instead tested for impairment at least annually. SFAS 142 also requires that Trust funds are maintained for each regulatory intangible assets with finite useful lives be jurisdiction and managed by investment amortized over their respective estimated lives to managers, who must comply with the guidelines the estimated residual values. In accordance with and rules of the applicable regulatory authorities. SFAS 142, for all business combinations with an The trust assets are invested in order to optimize acquisition date before July 1,2001, we amortized the after-tax earnings of the Trust, giving goodwill and intangible assets with indefinite lives consideration to liquidity, risk, diversification, and through December 2001, and then ceased other prudent investment objectives. amortization. The goodwill associated with those business combinations with an acquisition date Securities held in trust funds for decommissioning before July 1, 2001 was amortized on a straight- nuclear facilities and for the disposal of spent line basis generally over 40 years except for the nuclear fuel are included in Other Assets at portion of goodwill associated with gas trading market value in accordance with SFAS 115, and marketing activities which was amortized on a "Accounting for Certain Investments in Debt and straight-line basis over 10 years. In accordance Equity Securities. Securities in the trust funds with SFAS 142, for all business combinations with have been classified as available-for-sale due to an acquisition date after June 30, 2001, we have their long-term purpose. Inaccordance with SFAS not amortized goodwill and intangible assets with 71, unrealized gains and losses from securities in indefinite lives. Intangible assets with finite lives these trust funds are not reported in equity but continue to be amortized over their respective result in adjustments to the liabilityaccount forthe estimated lives ranging from 5 to 10 years. See nuclear decommissioning trust funds and to Note 3 for total goodwill, accumulated regulatory assets or liabilities for the spent nuclear amortization and the impact on operations of the fuel disposal trust funds in accordance with their adoption of SFAS 142. treatment in rates. In early 2002, we began testing our goodwill and Comprehensive Income (Loss) - Comprehensive intangible assets with indefinite useful lives for income (loss) is defined as the change in equity impairment, in accordance with SFAS 142. See (net assets) of a business enterprise during a Note 3 for the results of our testing and the period from transactions and other, events and corresponding net transitional impairment loss circumstances from non-owner sources. It recorded as a Cumulative Effect of Accounting includes all changes in equity during a period Change during 2002. except those resulting from investments by L-1 0
owners and distributions to owners. segment as viewed by the chief operating Comprehensive income (loss) has two decision-maker. See Note 16, "Business components: net income (loss) and other Segments for further discussion and details comprehensive income (loss). There were no regarding segments. material differences between net income and comprehensive income for AEGCo. Common Stock Options At December 31, 2002, AEP has two stock-based employee Components of Other Comprehensive Income compensation plans with outstanding stock (Loss) Other comprehensive income (loss) is options, which are described more fully in Note included on the balance sheet in the equity 15. AEP accounts for these plans under the section. The following table provides the recognition and measurement principles of APB components that comprise the balance sheet Opinion No. 25, Accounting for Stock Issued to amount in Accumulated Other Comprehensive Employees and related Interpretations. No stock-Income (Loss) for AEP. based employee compensation expense is reflected in AEP s earnings, as all options granted under these plans had exercise prices equal to or December 31, above the marketvalue of the underlying common 2002 2001 2000 (in millions) stock on the date of grant. The following table Foreign Currency Adjustments S 4 S(113) S (99) illustrates the effect on AEP s net income (loss) unrealized Losses (2) - - and earnings (loss) per share as if AEP had on Securities unrealized Gain on applied the fair value recognition provisions of Hedged Derivatives Minimum Pension (16) (3) - FASB Statement No. 123, "Accounting for Stock-Liability Based Compensation , to stock-based employee (595) (c ) (4) compensation. Year Ended December 31, Accumulated Other Comprehensive Income 2002 2001 2000 (Loss) for AEP registrant subsidiaries as of (in millions except per share data) December 31, 2002 and 2001 is shown in the Net Income(Loss), as reported $ (519) S 971 $ 267 following table. Registrant subsidiary balances Deduct: Total stock-for Accumulated Other Comprehensive Income based employee compensation (Loss) for the year ended December 31, 2000 expense determined was zero. under fair value based method for all awards, net of December 31, related tax effects (12) components 2002 2001 Pro forma net income L__) LZ34 (in thousands) (loss) 5Th57) S-95 5.3 0 cash Flow Hedges: APCO S(1,920) S (340) Earnings (Loss) per cSPco (267) share: I&M (286) (3,835) Basic as reported S-UI5) S2Z97 SO. S3 KPCo 322 (1,903) Basic pro forma oPco (738) (196) PSO (42) Diluted _____) SIZAZg OM18 SWEPCo (48) as reported TCC (36) Diluted pro forma TNC (15) Minimum Pension Liability: Earnings Per Share (EPS) AEP calculates APCO S(70,162) earnings (loss) per share in accordance with cSPco (59,090) INM (40,201) SFAS No. 128, "Earnings Per Share (see Note KPCO (9,773) oPco (72,148) 19). Basic earnings (loss) per common share is PSO SWEPCo (54,431) (53,635) calculated bydividing neteamings (loss) available TCC (73,124) to common shareholders by the weighted average TNC (30,748) number of common shares outstanding during the'- period. Diluted earnings (loss) per common share Segment Reporting The AEP System has is calculated by adjusting the weighted average adopted SFAS No. 131, which requires disclosure outstanding common shares, assuming of selected financial information by business L-1 I
conversion of all potentially dilutive stock options recent market transactions and cash flow and awards. The effects of stock options have projections. As a result of that testing, AEP not been included in the fiscal 2002 diluted loss determined that there was a net transitional per common share calculation as their effect impairment loss, which is reported as a would have been anti-dilutive. Basic and diluted cumulative effect of a change in accounting EPS are the same in 2002, 2001 and 2000. principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, sales of impaired assets. SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report SFAS 142 also changed the accounting and EPS. reporting for goodwill and other intangible assets. In accordance with SFAS 142 goodwill and Reclassification Beginning in the fourth quarter indefinite lived intangible assets acquired through of 2002, AEP and its registrant subsidiaries acquisition after June 30, 2001 were not elected to begin netting certain assets and amortized. Effective January 1, 2002, liabilities related to forward physical and financial amortization related to goodwill and indefinite transactions. This is done in accordance with lived intangible assets acquired before July 1, FASB Interpretation No. 39, "Offsetting of 2001 ceased. SFAS 142 requires that other Amounts Related to Certain Contracts and intangible assets be separately identified and if Emerging Issues Task Force Topic D-43, they have finite lives, they must be amortized over "Assurance That a Right of Setoff is Enforceable that life. See Note 3 for amortization lives of in a Bankruptcy under FASB Interpretation No. AEP s and SWEPCo s intangible assets. 39 . Transactions with common counterparties have been netted at the applicable entity level, by SFAS 143, "Accounting for Asset Retirement commodity and type (physical or financial) where Obligations , is effective for AEP on January 1, the legal right of offset exists. For comparability 2003. SFAS 143 generally applies to legal purposes, prior periods presented in this report obligations associated with the retirement of long-have been netted in accordance with this policy. lived assets. A company is required to recognize an estimated liability for any legal obligations Certain additional prior year financial statement associated with the future retirement of its long-items have been reclassified to conform to current lived assets. The liability is measured atfairvalue year presentation. Such reclassifications had no and is capitalized as part of the related assets impact on previously reported net income. capitalized cost. The increase in the capitalized cost is included in determining depreciation New Accounting Pronouncements expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 SFAS 142, "Goodwill and Other Intangible will be recorded as a cumulative effect of an Assets, was effective for AEP on January 1, accounting change. Additionally, because the 2002. The adoption of SFAS 142 required the asset retirement obligation is recorded initially at transition testing for impairment of all indefinite fair value, accretion expense (similar to interest) lived intangibles by the end of the first quarter will be recognized each period as an operating 2002 and initial testing of goodwill by the end of expense in the statement of operations. the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its The regulated entities have an asset retirement domestic operations and its indefinite lived obligation associated with nuclear intangible assets and there was no impairment. decommissioning costs for the Cook and STP Inthe second quarter 2002, AEP completed initial Nuclear Plants (affects l&M and TCC) and testing for goodwill impairment of the U.K. and possibly other obligations. AEP expects to Australian retail electricity and supply operations. establish regulatory assets and liabilities that will The fair values of the U.K. and Australia retail result in no cumulative effect adjustment of electricity and supply operations were estimated adopting SFAS 143 for the regulated entities. using a combination of market values based on L-1 2
In addition, the regulated transmission and 121, "Accounting for Long-lived Assets and for distribution entities have asset retirement Long-lived Assets to be Disposed Of. AEP obligations related to the final retirement of certain adopted SFAS 144 effective January 1, 2002. transmission and distribution lines. There are The adoption of SFAS 144 did not materially also underground storage tanks located at various affect AEP s results of operations or financial sites throughout the AEP System and PCB s are conditions. See Notes 3 and 13 for discussion of contained in certain transformer rectifier sets at impairments recognized in 2002 by AEP and its power plants. The amounts relating to these registrant subsidiaries, affected by SFAS 144. obligations cannot be determined because the entities are not able to estimate the final In April 2002, the FASB issued SFAS 145, retirement dates for these facilities. "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and In January 2003, the SEC Staff concluded that Technical Corrections'. SFAS 145 rescinds SFAS 143 also precludes an entity from recording SFAS 4, "Reporting Gains and Losses from an expense for estimated costs associated with Extinguishment of Debt", effective for fiscal years the removal or retirement of assets that result beginning after May 15, 2002. SFAS 4 required from other than legal obligations. The SEC Staff gains and losses from extinguishment of debt to concluded that amounts that are included in be aggregated and classified as an extraordinary accumulated depreciation related to estimated item if material. In 2003, for financial reporting removal costs arising from other than legal purposes AEP and TCC will reclassify obligations should be written off as part of the extraordinary losses net of tax on TCC s cumulative effect of adopting SFAS 143 unless reacquired debt of $2 million for 2001. the company is regulated under SFAS 71. Companies regulated under SFAS 71 may In October2002, the Emerging Issues Task Force continue to include removal costs in depreciation of the FASB reached a final consensus on Issue rates but must quantify the removal costs No. 02-3, "Recognition and Reporting of Gains included in accumulated depreciation as and Losses on Energy Contracts under Issues regulatory liabilities in footnote disclosure. The No. 98-10 and 00-17 (EITF 02-3). EITF 02-3 AEP registrant subsidiaries that are regulated rescinds EITF 98-10 and related interpretive entities have included estimated removal costs for guidance. Under EITF 02-3, mark-to-market non-legal retirement obligations in book accounting is precluded for energy trading depreciation rates. contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 For non-regulated entities, including certain will also eliminate any basis for recognizing formerly regulated generation facilities, asset physical inventories at fair value other than as retirement obligations associated with wind farms, provided by generally accepted accounting closure costs associated with power plants in the principles. The consensus is effective for fiscal U.K. and possibly other items will be incurred. periods beginning after December 15, 2002, and Also the amount of removal costs embedded in applies to all energy trading contracts entered into accumulated depreciation is expected to result in and inventory purchased through October 25, a favorable cumulative effect adjustment to net 2002. Effective January 1, 2003, nonderivative income. However, AEP and its registrant energy contracts are required to be accounted for subsidiaries have not completed their on a settlement basis and inventory is required to determination of the net effect of these items on be presented at the lower of cost or market. The first quarter 2003 results of operations upon the effect of implementing this consensus will be adoption of the provisions of this standard. reported as a cumulative effect of an accounting change. Such contracts and inventory will In August 2001, the FASB issued SFAS 144, continue to be accounted for at fair value through "Accounting for the Impairment or Disposal of December 31,2002. Energycontracts that qualify Long-lived Assets which sets forth the as derivatives will continue to be accounted for at accounting to recognize and measure an fair value under SFAS 133. impairment loss. This standard replaced, SFAS L-1 3
Effective January 1,2003, EITF 02-3 requires that initially be measured and recorded at fair value. gains and losses on all derivatives, whether The timing of recognizing future costs related to settled financially or physically, be reported in the exit or disposal activities, including restructuring, income statement on a net basis if the derivatives as well as the amounts recognized may be are held for trading purposes. Previous guidance affected by SFAS 146. AEP will adopt the in EITF 98-10 permitted non-financial settled provisions of SFAS 146 for exit or disposal energy trading contracts to be reported either activities initiated after December 31, 2002. gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant In November 2002, the FASB issued subsidiaries recorded and reported upon Interpretation No. 45, "Guarantors Accounting settlement, sales under forward trading contracts and Disclosure Requirements for Guarantees, as revenues and purchases under forward trading Including Indirect Guarantees of Indebtedness of contracts as purchased energy expenses. Others (FIN 45) which requires that a liability Effective July 1, 2002, AEP and its registrant related to issuing a guarantee be recognized, as subsidiaries reclassified such forward trading well as additional disclosures of guarantees. revenues and purchases on a net basis, as This new guidance is an interpretation of SFAS permitted by EITF 98-10. The reclassification of Nos. 5, 57 and 107 and a rescission of FIN No. such trading activity to a net basis of reporting 34. The initial recognition and initial resulted in a substantial reduction in both measurement provisions of FIN 45 are effective revenues and purchased energy expense, but did on a prospective basis to guarantees issued or not have any impact on financial condition, results modified after December 31, 2002. The of operations or cash flows. disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods Effective July 1, 2002, AEP and its registrant ending after December 15, 2002. We do not subsidiaries modified their valuation procedures expect that the implementation of FIN 45 will for estimating the fair value of energy trading materially affect results of operations, cash flows contracts at inception. Unrealized gain or loss at or financial condition. See guarantee details inception is recognized only when the fair value of discussed in Note 10. a contract is obtained from a quoted market price in an active market or is otherwise evidenced by In December 2002, the FASB issued SFAS No. comparison to other observable market data. Any 148, "Accounting for Stock-Based Compensation-fair value changes subsequent to the inception of Transition and Disclosure , which amends SFAS a contract, however, are recognized immediately No. 123, "Accounting for Stock-Based based on the best market data available. AEP Compensation . SFAS 148 provides alternative and its registrant subsidiaries now also use such methods of transition for a voluntary change to procedures for determining unrealized gain or the fair value based method of accounting for loss at inception for all derivative contracts. stock-based employee compensation. Underthe fair value based method, compensation cost for In June 2002, FASB issued SFAS 146 which stock options is measured when options are addresses accounting for costs associated with issued. In addition, SFAS 148 amends the exit or disposal activities. This statement disclosure requirements of SFAS 123 to require supersedes previous accounting guidance, more prominent and more frequent (quarterly) principally EITF No. 94-3, "Liability Recognition for disclosures in financial statements of the effects Certain Employee Termination Benefits and Other of stock-based compensation. SFAS 148 is Costs to Exit an Activity (including Certain Costs effective for fiscal years ending after December Incurred in a Restructuring). Under EITF No. 94- 15, 2002. AEP does not currently intend to adopt 3, a liability for an exit cost was recognized at the the fair value based method of accounting for date of an entitys commitment to an exit plan. stock options. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be In November2002, the FASB issued an Invitation recognized when the liability is incurred. SFAS to Comment, "Accounting for Stock-Based 146 also establishes that the liability should Compensation: A Comparison of FASB L-14
Statement No. 123, Accounting for Stock-Based AEP and its subsidiaries believe it is reasonably Compensation, and Its Related Interpretations, possible that they will be required to consolidate and IASB Proposed IFRS, Share-Based identified variable interest entities as a result of Payment. The FASB plans to make a decision this new guidance. See Notes 9, 22, 23 and 26 in the first quarter of 2003 whether it will begin a for additional disclosures relating to the variable more comprehensive reconsideration of the interest entities. accounting for stock options. This may include revisiting the decision in SFAS 123 allowing 2. Extraordinary Items and Cumulative Effect: companies to disclose the pro forma effects of the fair value based method rather than requiring Extraordinary Items Extraordinary items were recognition of the fair value of employee stock recorded for the discontinuance of regulatory options as an expense. accounting under SFAS 71 for the generation portion of the business in the Ohio, Virginia, West In January 2003, the FASB issued FASB Virginia, Texas and Arkansas state jurisdictions. Interpretation No. 46, "Consolidation of Variable See Note 7 "Customer Choice and Industry Interest Entities (FIN 46) which changes the Restructuring fordescriptionsofthe restructuring requirements for consolidation of certain entities plans and related accounting effects. OPCo and in which equity investors do not have the CSPCo recognized an extraordinary loss for characteristics of a controlling financial interest or stranded Ohio Public Utility Excise Tax do not have sufficient equity at risk for the entity to (commonly known as the Gross Receipts Tax finance its activities without additional GRT) net of allowable Ohio coal credits during the subordinated financial support from other parties. quarter ended June 30, 2001. This loss resulted This new guidance is an interpretation of from regulatory decisions in connection with Ohio Accounting Research Bulletin (ARB) No. 51, deregulation which stranded the recovery of the "Consolidated Financial Statements . The initial GRT. Effective with the liability affixing on May 1, recognition and initial measurement provisions of 2001, CSPCo and OPCo recorded an FIN 46 for all enterprises with variable interests in extraordinary loss variable interest entities created afterJanuary 31, 2003, shall apply the provisions of this Interpretation to those entities immediately. A public entity with variable interests in variable interest entities created before February 1, 2003 shall apply the provisions of this Interpretation no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. If it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest entity when this Interpretation becomes effective, the enterprise shall disclose the following information in all financial statements initially issued after January 31, 2003, regardless of the date on which the variable interest entity was created:
Year Ended requires that the purchase method of accounting December 31. 2002 2001 2000 be used for all business combinations initiated (in millions) after June 30, 2001 and established new Extraordinary Items: Discontinuance of Regulatory standards for the recognition of certain identifiable Accounting for Generation: Ohio jurisdiction (Net of Tax intangible assets, separate from goodwill. of $20 million in 2001 and Business combinations initiated after June 30,
$35 Million in 2000)(a) -$ 5(48) S(44)
Virginia and west Virginia 2001 (see Note 12 for details) are accounted for jurisdictions (Inclusive of utilizing SFAS 141. Tax Benefit of $8 Million)(b) - - 9 Loss on Reacquired Debt (Net of Tax of S1 Million SFAS 142 requires that goodwill and intangible in 2001)(c) (2) assets with indefinite useful lives no longer be Extraordinary Items S- S amortized, but instead tested for impairment at (a) Relates to AEP, oPCo and cspco. least annually. SFAS 142 required a two-step (b) Relates to AEP and APCo. (c) Relates to AEP and TCC. impairment test for goodwill. The first step was to compare the carrying amount of the reporting Cumulative Effect ofAccounting Change - SFAS unit s assets to the fair value of the reporting unit. 142 requires that goodwill and intangible assets If the carrying amount exceeded the fair value with indefinite useful lives no longer be amortized then the second step was required to be and be tested annually for impairment. The completed, which involves allocating the fairvalue implementation of SFAS 142 resulted in a $350 of the reporting unit to each asset and liability, million net transitional loss for our U.K. and with the excess being implied goodwill. The Australian operations and is reported in AEP s impairment loss is the amount by which the Consolidated Statements of Operations as a recorded goodwill exceeds the implied goodwill. cumulative effect of accounting change (see Note AEP was required to complete a 'transitional 3 for further details). impairment test for goodwill as of the beginning of the fiscal year in which the statement was The FASB s Derivative Implementation Group adopted. This transitional impairment test (DIG) issued accounting guidance under SFAS required that AEP complete step one of the 133 for certain derivative fuel supply contracts goodwill impairment test within six months from with volumetric optionality and derivative the date of initial adoption, or June 30, 2002. In electricity capacity contracts. This guidance, the first quarter 2002, AEP completed the effective in the third quarter of 2001, concluded transitional impairment test of goodwill related to that fuel supply contracts with volumetric domestic operations and indefinite lived intangible optionality cannot qualifyfora normal purchase or assets and concluded that those assets were not sale exclusion from mark-to-market accounting impaired. and provided guidance for determining when certain option-type contracts and forward In the second quarter 2002, AEP completed contracts in electricity can qualify for the normal testing for goodwill impairment on AEP s U.K. and purchase or sale exclusion. Australian retail electricity and supply operations. The fair values of the U.K. and Australian retail For AEP, the effect of initially adopting the DIG electricity and supply operations were estimated guidance at July 1, 2001 was a favorable using a combination of market values based on earnings mark-to-market effect of $18 million, net recent market transactions and cash flow of tax of $2 million. It was reported as a projections. As a result of this testing, AEP cumulative effect of an accounting change on determined that there was a net transitional AEP s Consolidated Statements of Operations. impairment loss of $350 million, which was reported in AEP s Consolidated Statements of
- 3. Goodwill and Other Intangible Assets: Operations as a Cumulative Effect of Accounting Change.
As described in the Significant Accounting Policies footnote, AEP adopted the provisions of SFAS 142 also requires that intangible assets SFAS 141 effective July 1, 2001. SFAS 141 with finite useful lives be amortized over their L-1 6
respective estimated lives to the estimated straight-line basis over 10 years. Also, in residual values. In accordance with SFAS 142, accordance with SFAS 142, for all business foral business combinations initiated before July combinations with acquisition dates after June 30, 1, 2001, AEP amortized goodwill and intangible 2001, AEP has not amortized goodwill and assets with indefinite lives through December intangible assets with indefinite lives. Intangible 2001, and then ceased amortization. The assets with finite lives continue to be amortized goodwill associated with those business over their respective estimated lives ranging from combinations with acquisition dates before July 1, 5 to 10 years. 2001 was amortized on a straight-line basis generally over 40 years except for the portion of New reporting requirements imposed by SFAS goodwill associated with gas trading and 142 include the disclosures shown below: marketing activities, which was amortized on a Goodwill The changes in AEP s the carrying amount of goodwill for the twelve months ended December 31, 2002 by operating segment are: Energy AEP wholesale Delivery other Consolidated (in millions) Balance January 1, 2002 $340 $37 $15 $392 Goodwill acquired 2 - - 2 changes to Goodwill due to purchase price adjustments 181 181 Non-transitional impairment losses (173) (12) (185) Foreign currency exchange rate changes 6 6 Balance December 31, 2002 3Sfi $31 $196 Accumulated amortization of goodwill was approximately $22 million and $25 million at December 31, 2002 and 2001, respectively. A decrease of $3 million related principally to the non-transitional impairment of goodwill on Gas Power Systems (see Note 13a). The transitional impairment loss related to SEEBOARD and CitiPower goodwill, which is reported as a cumulative effect of an accounting change, is excluded from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower, including goodwill and acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations in AEP s Consolidated Balance Sheets. See Note 12 related to the sale of SEEBOARD and CitiPower. Changes to goodwill due to purchase price adjustments of $181 million was primarily due to purchase price adjustments related to AEP s acquisition of U.K. Generation. The purchase price adjustments also include adjustments related to the acquisition of Houston Pipe Line Company, MEMCO, Nordic Trading and AEP Coal (see Note 12). Inthe first quarter of 2002, AEP recognized a goodwill impairment loss of $12 million for all goodwill related to the acquisition of Gas Power Systems (see Note 13a). In the fourth quarter of 2002, AEP prepared its annual goodwill impairment tests. The fair values of the operations were estimated using cash flow projections. There were no goodwill impairments as a result of the annual goodwill impairment tests. However, in the fourth quarter, AEP recognized goodwill impairment losses totaling $173 million related to impairment studies performed on the U.K. Generation assets ($166 million), AEP Coal ($3 million), and Nordic Trading ($4 million). These goodwill impairment studies were L-17
triggered by the SFAS 144 asset impairment losses recognized on these operations in the fourth quarter (refer to Note 13). The fair values of these operations were estimated using cash flow projections. The following tables show the transitional disclosures to adjust AEP s reported net income (loss) and earnings (loss) per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized. Net Income (Loss) Year Ended December 31. 2002 2001 2000 (in millions) Reported Net Income (Loss) $(519) $ 971 $267 Add back: Goodwill amortization (a) _ 39 39 Add back: Amortization for intangibles with indefinite lives under SFAS 142 (b) __ 8 9 Adjusted Net Income (Loss) $-51) $1 018 31 Twelve Months Ended Earnings (Loss) Per share (Basic and Dilutive) December 31, 2002 2001 2000 Reported Earnings (Loss) per Share $(1.57) $3.01 $0.83 Add back: Goodwill amortization Cc) - 0.12 0.12 Add back: Amortization for intangibles with indefinite lives under SFAS 142 (d) - 0.02 0.03 Adjusted Earnings (Loss) per Share $i(31.) $3.15 $0a98 (a) This amount includes $34 million and $37 million in 2001 and 2000 related to seeboard and citiPower amortization expense included in Discontinued operations on AEP s consolidated statements of operations. (b) The amounts shown for 2001 and 2000 relate to CitiPower amortization expense included in Discontinued Operations on AEP s consolidated Statements of operations. Cc) This amount includes $0.10 and $0.11 in 2001 and 2000 related to Seeboard and citipower amortization expense included in Discontinued Operations on AEP s Consolidated Statements of operations. (d) The amounts shown for 2001 and 2000 relate to citipower amortization expense included in Discontinued operations on AEP s consolidated statements of operations. L-1 8
Acquired Intangible Assets Acquired intangible assets subject to amortization are $37 million at December 31, 2002 and $33 million at December 31, 2001, net of accumulated amortization. Of those amounts, $25 million and $33 million at December 31,2002 and 2001, relate to SWEPCo. The gross carrying amount, accumulated amortization and amortization life by major asset class are: December 31, 2002 December 31, 2001 Gross Gross Amortization Carrying Accumulated carrying Accumulated Life Amount Amortization Amount Amortization (in years) (in millions) (in millions) Dolet Hills Advanced Royalties (SWEPCO) 10 $35 $5 S35 $2 Less: Adjustment Due to Purchase Price Reallocation (SWEPCO) 6 1 Trade name and Administration of Contracts 7 2 unpatented Technology 10 10 Totals ,$A $A Amortization of intangible assets (primarily 4. Merger: SWEPCo) was $2 million for the twelve months ended December 31, 2002. AEP s estimated On June 15,2000, AEP merged with CSW so that aggregate amortization expense is $4 million for CSW became a wholly-owned subsidiary of AEP. each year 2003 through 2008. SWEPCo s Under the terms of the merger agreement, estimated aggregate amortization expense approximately 127.9 million shares of AEP (included inAEP s estimated amount) is $3 million Common Stock were issued in exchange for all for each year 2003 through 2008. the outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share of AEP s acquired intangible assets no longer AEP Common Stock for each share of CSW subject to amortization were comprised of retail Common Stock. and wholesale distribution licenses for CitiPower operating franchises. The licenses were being The merger was accounted for as a pooling of amortized on a straight-line basis over 20 and 40 interests. Accordingly, AEP s consolidated years for the retail and wholesale licenses, financial statements give retroactive effect to the respectively. In accordance with SFAS 144, the merger, with all periods presented as if AEP and assets of CitiPower, including acquired intangible CSW had always been combined. Certain assets no longer subject to amortization, are reclassifications have been made to conform the reported as Assets of Discontinued Operations on historical financial statement presentation of AEP one line in AEP s Consolidated Balance Sheets. and CSW. Effective January 2003, the legal See Note 12 related to the sale of CitiPower. name of CSW was changed to AEP Utilities, Inc. In connection with the merger, $10 million ($7 million after tax), $21 million ($14 million after tax) L-1 9
and $203 million ($180 million after tax) of non- eight years through rate reductions which began recoverable merger costs were expensed in 2002, in the third quarter of 2000. 2001 and 2000. Such costs included transaction and transition costs not recoverable from Summary of key provisions of Merger Rate ratepayers. Also included in the merger costs Agreements: were non-recoverable changes in control State/Company Ratemaking Provisions payments. Merger transaction and transition Texas SWEPCo, $221 million rate reduction TCC, TNC over 6 years. costs of $52 million recoverable from ratepayers No base rate increases for were deferred pursuant to state regulator 3 years post merger. approved settlement agreements through Indiana I&M $67 million rate reduction December 31, 2002. The deferred merger costs over 8 years. Extension of base rate freeze until are being amortized over five to eight year January 1, 2005. Requires recovery periods, depending on the specific terms additional annual deposits of
$6 million to the nuclear of the settlement agreements, with the decommissioning trust fund for the years 2001 through amortization ($8 million, $8 million and $4 million 2003.
for the years 2002, 2001 and 2000) included in Michigan I&M Customer billing credits of depreciation and amortization expense. approximately 514 million over 8 years. Extension of base rate freeze until The following tables show the deferred merger January 1, 2005. cost and amortization expense of the applicable Kentucky KPCo Rate reductions of subsidiary registrants: approximately $28 million over 8 years. No base rate increases for Amortization 3 years post merger. Merger Cost Expense for the Deferral at Year Ended Oklahoma PSO Rate reductions of December 31. 2002 December 31. 2002 approximately $28 million (in millions) over 5 years. No base rate I&M $8.2 51.7 increase before January 1, KPCO 2.9 0.6 2003. PSO 5.0 1.6 SWEPCo 3.9 1.1 Arkansas SWEPCO Rate reductions of $6 million TCC 9.1 2.6 over 5 years. TNC 2.7 0.8 Louisiana SWEPCO Rate reductions to share Amortization merger savings estimated to Merger Cost Expense for the be $18 million over 8 Deferral at Year Ended years. Base rate cap until December 31. 2001 December 31. 2001 June 2005. (in millions) I&M $ 9.1 $1.7 KPCo PSO 3.2 6.6 0.6 1.2 If actual merger savings are significantly less than SWEPCO 5.0 1.1 the merger savings rate reductions required by TCC TNC 11.8 3.5 2.6 0.8 the merger settlement agreements in the eight-year period following consummation of the Amortization Merger Cost Expense for the merger, future results of operations, cash flows Deferral at Year Ended and possibly financial condition could be December 31. 2000 December 31. 2000 (in millions) adversely affected. I&M $ 6.9 S0.7 KPCO 2.5 0.3 PSO 7.9 0.5 See Note 9, "Commitments and Contingencies SWEPCo TCC 6.1 14.4 0.5 1.3 for information on a court decision concerning the TNC 4.2 0.4 merger. Merger transition costs are expected to continue 5. Nuclear Plant Restart: to be incurred for several years after the merger and will be expensed or deferred for amortization I&M completed the restart of both units of the as appropriate. As hereinafter summarized, the Cook Plant in 2000. Cook Plant is a 2,110 MW state settlement agreements provide for, among two-unit plant owned and operated by I&M under other things, a sharing of net merger savings with licenses granted by the NRC. I&M shut down certain regulated customers over periods of up to both units of the Cook Plant, in September 1997, L-20
due to questions regarding the operability of The amortization of O&M costs and fuel-related certain safety systems that arose during a NRC revenues deferred under Indiana and Michigan architect engineer design inspection. retail jurisdictional settlement agreements will adversely affect results of operations through Settlement agreements in the Indiana and December 31, 2003 when the amortization period Michigan retail jurisdictions that address recovery ends. The annual amortization of O&M costs and of Cook Plant related outage costs were approved fuel-related revenue deferrals is approximately in 1999. The IURC approved a settlement $78 million. agreement that resolved all matters related to the recovery of replacement energy fuel costs and all 6. Rate Matters: outage/restart costs and related issues during the extended outage of the Cook Plant. The MPSC TexasFuel AffectingAEP, SWEPCo, TCCand approved a settlement agreement for two open TNC Michigan power supply cost recovery reconciliation cases that resolved all issues Prior to the start of retail competition in ERCOT related to the Cook Plant extended outage. The on January 1, 2002, fuel recovery for Texas settlement agreements allowed: utilities was a multi-step procedure. When fuel costs changed, utilities filed with the PUCT for
- Deferral of $200 million of non-fuel nuclear authority to adjust fuel factors. If a utility s prior operation and maintenance (O&M) costs for fuel factors resulted in material over-recovery or amortization over five years ending December under-recovery of fuel costs, the utility would also 31, 2003, request a refund or surcharge factor to refund or
- Deferral of certain unrecovered fuel and collect those amounts. While fuel factors were power supply costs for amortization over five intended to recover fuel costs, final settlement of years ending December 31, 2003, these amounts was subject to reconciliation and
- A freeze in base rates through December 31, approval by the PUCT.
2003 and a fixed fuel recovery charge through March 1, 2004 in the Indiana jurisdiction, Fuel reconciliation proceedings determine
- A freeze in base rates and fixed power supply costs recovery factors until January 1, 2004 whether fuel costs incurred during the for the Michigan jurisdiction. reconciliation period were reasonable and necessary. All fuel costs incurred since the prior The amount of costs and deferrals charged to reconciliation date are subject to PUCT review other operation and maintenance expenses were and approval. If material amounts are determined as follows: to be unreasonable and ordered to be refunded to customers, results of operations and cash flows Year Ended December 31.
2002 2001 2000 would be negatively impacted. Costs Incurred $- $1 S297 Amortization of Deferrals 40 40 40 According to Texas Restructuring Legislation, fuel charged to o&M Expense SAD $41 S33Z cost in the Texas jurisdiction after 2001 is no longer subject to PUCT review and reconciliation. At December 31, 2002 and 2001, deferred O&M During 2002, TCC and TNC filed final fuel costs of $40 million and $80 million, respectively, reconciliations with the PUCT to reconcile their remained in Regulatory Assets to be amortized fuel costs through the period ending December through 2003. Also pursuant to the settlement 31, 2001. The ultimate recovery of deferred fuel agreements, accrued fuel-related revenues of $38 balances at December 31, 2001 will be decided million were amortized as a reduction of revenues as part of their 2004 true-up proceedings. See in each of 2002, 2001 and 2000. At December discussion of TCC and TNC fuel reconciliations 31, 2002 and 2001, fuel-related revenues of $37 below. million and $75 million, respectively, were included in Regulatory Assets and will be In October 2001, the PUCT delayed the start of amortized through December 31, 2003 for both customer choice in the SPP area of Texas. All of jurisdictions. SWEPCo s Texas service territory and a small L-21
portion of TNC s service territory are in SPP. beat adjustment. With the sale of the REPs to SWEPCo s existing Texas fuel cost recovery Centrica in December 2002, Centrica is procedures will continue until competition begins. responsible for these appeals. Any adverse ruling SWEPCo will continue to set fuel factors and from the appeal could impact TCC and TNC by determine final fuel costs in fuel reconciliation requiring refunds for the time period AEP served proceedings during the SPP delay period. The the retail customers prior to the sale to Centrica PUCT has ruled that TNC fuel factors in the SPP (January 2002 to December 2002). area will be based upon the price-to-beat fuel factors offered by the retail electric provider in the TCC Fuel Reconciliation - Affecting AEP and ERCOT portion of TNC s service territory. TNC TCC transferred its SPP customers to Mutual Energy SWEPCo effective December 1,2002. TNC filed In December 2002, TCC filed with the PUCT to in 2002 with the PUCT to determine the most reconcile fuel costs and to defer its over-recovery appropriate method to reconcile fuel costs in of fuel for inclusion in the 2004 true-up TNC s SPP area and a decision is expected by proceeding. This reconciliation for the period of mid 2003. July 1998 through December 2001 will be the final fuel reconciliation. At December 31, 2001, the Under Texas restructuring, customer choice to over-recovery balance for TCC was $63.5 million select a retail electric provider began January 1, including interest. During the reconciliation 2002. Sales to customers using 1 MW or less will period, TCC incurred $1.6 billion of eligible fuel be at fixed base rates during a transition period and fuel-related expenses. Recommendations from 2002 through 2006. As discussed in Note from intervening parties are expected in April 12 "Acquisitions, Dispositions and Discontinued 2003 with hearings scheduled in May 2003. A Operations, AEP sold its Texas retail electric final order is expected in late 2003. An adverse providers (REP) and their retail customers in ruling from the PUCT could have a material December 2002. impact on future results of operations, cash flows and financial condition. Additional information The formerAEP subsidiaries serving as REPs for regarding the 2004 true-up proceeding for TCC the ERCOT area filed with the PUCT in May 2002 can be found in Note 8 "Customer Choice and to increase the fuel portion of their price-to-beat Industry Restructuring . rate in compliance with the Texas Restructuring Legislation and the PUCT s rules. The Texas TNC Fuel Reconciliation Affecting AEP and legislation provides for the adjustment of the fuel TNC portion of the rate up to twice annually to reflect significant changes in the market price of natural In June 2002, TNC filed with the PUCT to gas and purchased energy used to serve retail reconcile fuel costs and to defer any unrecovered customers using NYMEX natural gas prices. On portion applicable to retail sales within its ERCOT July 15,2002, the PUCT required further hearings service area for inclusion in the 2004 true-up to reconsider the validity of their existing rules for proceeding. This reconciliation for the period of fuel factor adjustments. On July 24, 2002, the July 2000 through December 2001 will be the final Texas REPs filed a petition with the District Court fuel reconciliation for TNC s ERCOT service seeking an injunction commanding the PUCT to territory. At December 31, 2001, the under-proceed to a final order based on the existing recovery balance associated with TNC s ERCOT rules and prohibiting the PUCT from conducting a service area was $27.5 million including interest. remand proceeding. The District Court issued an During the reconciliation period, TNC incurred order on August 9, 2002 requiring the PUCT to $293.7 million of eligible fuel costs serving both comply with the existing rules. On August 26, ERCOT and SPP retail customers. TNC also 2002, the PUCT issued an order approving a 22% requested authority to surcharge its SPP increase to the fuel portion of the price-to-beat customers. TNC s SPP customers will continue rates effective immediately for both REPs. The to be subject to fuel reconciliations until PUCT order approving the 22% increase has competition begins in SPP. The under-recovery been appealed by parties opposing the price-to- balance at December 31, 2001 for TNC s service L-22
within SPP was $0.7 million including interest. including power generation companies and retail electric providers. In August 2001, ERCOT In October 2002, the filing was split into two incurred substantial costs for managing phases for hearing purposes. The first phase transmission in its north zone. The costs incurred examined all components of the filing except for by ERCOT to manage congestion are shared by AEP trading activities and the associated margins all ERCOT QSEs. In late 2001, the PUCT that flow back to customers as an offset to fuel initiated an investigation of the impact of costs consistent with the PUCT - approved Texas scheduling of electric loads and resources by merger settlement. Intervenors filed testimony in QSEs during August 2001. The PUCTs the first phase recommending that up to $25 investigation determined that a substantial million of TNC s requested retail eligible fuel amount of the congestion charges were the result recovery be disallowed and hearings were held on of QSEs, including AEP s QSE, scheduling more October 23, 2002. TNC disputed the resources than required to meet their actual load recommendations. On October 21, 2002, the requirements in the ERCOT north zone. AEP s PUCT Staff and Office of Public Utility Counsel QSE over-scheduled resources due to an error in (OPC) filed a joint Motion for Summary Decision the allocation of estimated load requirements related to the second phase issue and requested between ERCOT congestion zones. Pursuant to that approximately $18.5 million of TNC s retail the PUCT s investigation, QSEs, including AEP s eligible fuel recovery be disallowed without a QSE, agreed to a settlement that provides for the hearing. On November 8, 2002, the refund of payments received for adjusting administrative law judges (ALJs) in the case resource schedules for congestion. The denied the motion. The intervenors filed settlement was approved by the PUCT in testimony on October 29, 2002 in the second November 2002. The settlement recognizes that phase recommending that up to $34 million of the scheduling errors were associated with the TNC s requested retail eligible fuel recovery be start up of the ERCOT competitive market AEP's disallowed. The intervenors recommended QSE paid $3.2 million to ERCOT and received disallowance includes the amount sought in the $1.7 million from ERCOT in congestion refunds October 21 Motion for Summary Decision. The for a net payment of $1.5 million. Payments were total intervenor recommended retail disallowance assigned to TNC and the refunds were allocated is approximately $59 million. Hearings for the to TCC and TNC. TNC incurred a net cost of second phase were held on November 13-14, $2.8 million and TCC received a refund of $1.3 2002. On February 3, 2003, TNC filed a motion million. The TNC payment and TCC refund have to reopen the evidentiary record and include a been reflected in the final fuel reconciliation filings decrease to retail eligible fuel costs of $1.3 for each company. However, intervening parties million, including interest, to reflect final have objected to the inclusion of the TNC resettlement revenues and expenses from payment in its final fuel reconciliation. ERCOT for the period August through December Recommendations from intervening parties in the 2001 (see discussion in Fuel and Purchased TCC proceeding are not expected until April 2003. Power below). The PUCT is expected to issue a An adverse ruling from the PUCT would impact final order in this case by mid 2003. An adverse future results of operations, cash flows and ruling from the PUCT could have a material financial condition. impact on future results of operations, cash flows and financial condition. Texas Transmission Rates - Affecting AEP, TCC and TNC ERCOT Over-scheduling Affecting AEP, TCC and TNC On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism ERCOT began serving as a central control center created by the PUCT in 1996 and used for the for all of ERCOT at the end of July 2001 when period January 1, 1997 through August 31,1999 ERCOT became a single control area. Qualified was invalid. The court upheld an appeal filed by scheduling entities (QSE) schedule loads and unaffiliated Texas utilities that the PUCT resources for ERCOT market participants exceeded its statutory authority to set such rates L-23
during that period. TCC and TNC were not from January 1, 1997. In July 2002, FERC parties to the case. However, the companies approved a revised open access transmission transmission sales and purchases were priced tariff and refunds of $1.3 million were issued to using the invalid rates. It is unclear what action unaffiliated entities. the PUCT will take to respond to the court s ruling. If the PUCT changes rates retroactively, Under FERC rules, the new tariffs resulted in a the result could have a material unfavorable reallocation of previously received transmission impact on results of operations and cash flows for revenues among affiliates resulting in the TCC and TNC. following income statement impact: Increase (Decrease) Revenues FERC Wholesale Fuel Complaints Affecting 2001 2002 Total AEP and TNC (in millions) PSO S 2.8 $ 2.5 S 5.3 In May 2000, certain TNC wholesale customers 3.2 2.8 6.0 SWEPCo filed a complaint with FERC alleging that TNC had overcharged them through the fuel TCC (6.0) (2.8) (8.8) adjustment clause for certain purchased power TNC (2.6) (1.2) (. 8) costs related to 1999 unplanned outages at AEP Total SV-6) S 1.3 a) TNC s Oklaunion generation station. In November 2001, certain TNC wholesale customers filed an additional complaint at FERC Fuel and Purchased Power Affecting AEP, asserting that since 1997 TNC had billed PSO, SWEPCo, TCC and TNC wholesale customers for not only the 1999 Oklaunion outage costs, but also certain PSO has Under-Recovered Fuel Costs of $75.7 additional costs that are not permissible underthe million at December 31, 2002, representing fuel fuel adjustment clause. and purchased power costs recorded but not yet collected from retail customers in Oklahoma. The In December 2001, FERC issued an order first significant item causing the under-recovery is requiring TNC to refund, with interest, amounts approximately $44 million in reallocation of associated with the May 2000 complaint thatwere purchased power costs for periods prior to previously billed to wholesale customers. The January 1, 2002, as described below. The other effects of this order were recorded in 2001. In significant item impacting the under-recovered response to the November 2001 complaint, fuel costs are natural gas price increases that negotiations to settle the complaint and update were not expected when PSO set its quarterly the contracts are continuing. In March 2002, TNC factors during 2002. The Corporation recorded a provision for refund of $2.2 million Commission of the State of Oklahoma (OCC) is before income taxes. The actual refund and final currently reviewing the reasons for the large resolution of this matter could differ materially under-recovered balance. from this estimate and may have a negative impact on future results of operations, cash flows The AEP West electric operating companies and financial condition. power is dispatched real-time on an economic basis and is later allocated among the AEP West FERC Transmission Rates AffectingAEP, PSO, electric operating companies using the SWEPCo, TCC and TNC Interchange Cost Reconstruction (ICR) system based on dispatch information from internal and In November 2001, FERC issued an order external sources. ICR is designed to allocate the resulting from a remand by an appeals court of a cost of power under the terms and conditions of tariff compliance filing order issued in 1998 that the AEP West Operating Agreement. During had been appealed by certain customers. The 2002, two ICR adjustments were made. The order required PSO, SWEPCo, TCC and TNC to adjustments were related to a 2002 true-up and a submit revised open access transmission tariffs reallocation of years prior to 2002. and calculate and issue refunds for overcharges L-24
During the third quarter of 2002, AEP reallocated PSO Rate Review Affecting AEP and PSO purchased power costs among the fourAEP West electric operating companies for the periods prior In February 2003, the Director of the OCC filed an to January 1, 2002 (the ICR Adjustments). The application requiring PSO to file all documents effects of the reallocation on pre-tax income were necessary for a general rate review before August insignificant to PSO and TCC and increased pre- 1, 2003. Management is unable to predict the tax income at SWEPCo and TNC by $2.4 million result of this review as the documents and data and $1.9 million, respectively. have not been assembled. The formation of the ERCOT single control zone Louisiana Compliance Filing AffectingAEP and increased the need for data estimation and true- SWEPCo up which has resulted in extended true-up periods associated with allocations being performed on On October 15, 2002, SWEPCo filed with the estimated data. ERCOT can make adjustments Louisiana Public Service Commission (LPSC) to companies settlements for up to six months. A detailed financial information typically utilized in a true-up process for 2002 was completed and revenue requirement filing, including a recorded in the fourth quarter of 2002 resulting in jurisdictional cost of service. This filing was insignificant changes in PSO s and SWEPCo s required by the LPSC as a result of their order pre-tax income. TCC s pre-tax income was approving the merger between AEP and CSW. reduced by $3.7 million and TNC s pre-tax income The LPSC s merger order also provides that was increased by $4.8 million. As ERCOT SWEPCo s base rates are capped at the present notifies TCC and TNC of further adjustments, they level through mid 2005. The filing indicates that will be recorded. SWEPCo s current rates should not be reduced. If the LPSC disagrees with our conclusion, they PSO implemented new fuel rates in December could order SWEPCo to file all documents for a 2002 following the OCC s review and approval. full cost of service revenue requirement review in The new fuel factors were designed to recover order to determine whether SWEPCo s capped estimated fuel costs for the next three months and rates should be reduced which would adversely to begin recovery of the under-recovered amount. impact results of operations and cash flows. Recovery of the under-recovered amount is expected to occur over several months and is FERC Long-term Contracts Affecting AEP and subject to OCC review and approval. AEP East and AEP West companies For SWEPCo, the true-up process described In September 2002, the FERC voted to hold above and the ICR Adjustments resulted in a net hearings to consider requests from certain increase in fuel costs recoverable from customers wholesale customers located in Nevada and of $8 million included in Regulatory Assets on Washington to break long-term contracts which AEP s and SWEPCo s Consolidated Balance they allege are 'high-priced . At issue are long-Sheets. The amount is recoverable from term contracts entered during the California customers pursuant to the applicable fuel energy price spike in 2000 and 2001. The recovery mechanisms and review of the state complaints allege that AEP sold power at unjust regulatory commissions in Arkansas, Louisiana and unreasonable prices. The FERC delayed and Texas. hearings to allow the parties to hold settlement discussions. In January 2003, the FERC To the extent the OCC and/or the AEP West settlement judge assigned to the case indicated Commissions regulating SWEPCo do not permit that the parties' settlement efforts were not recovery of the revised fuel and purchased power progressing and he recommended that the costs, there could be an adverse effect on results complaint be placed back on the schedule for a of operations and cash flows. hearing. In February 2003, AEP and one of our customers agreed to terminate their contract with the customer withdrawing its FERC complaint. L-25
In a similar complaint, a FERC administrative law SFAS 71 requires that the AEP System's judge (ALJ) ruled in favor of AEP and dismissed, regulated rates be cost-based and the recovery of in December 2002, a complaint filed by two regulatory assets be probable. Management has Nevada utilities. In2000 and 2001, AEP agreed reviewed all the evidence currently available and to sell power to the utilities for future delivery. In concluded that the requirements to apply SFAS late 2001, the utilities filed complaints that the 71 continue to be met for all electric operations in prices for power supplied under those contracts Indiana, Kentucky, Louisiana, Michigan, should be lowered because the market for power Oklahoma and Tennessee. was allegedly dysfunctional at the time such contracts were entered. The AU rejected the When the generation portion of the business in utilities' complaint, held that the markets for Arkansas, Ohio, Texas, Virginia and West Virginia future delivery were not dysfunctional, and that no longer met the requirements to apply SFAS 71, the utilities had failed to demonstrate that the net regulatory assets were written off for that public interest required that changes be made to portion of the business unless they were the contracts. The ALJ's order is preliminary and determined to be recoverable as a stranded cost is subject to review by the FERC. The FERC will through regulated distribution rates or wire likely rule on the ALJ's order in 2003. charges in accordance with SFAS 101 and EITF Management is unable to predict the outcome of 97-4. In the Ohio and West Virginia jurisdictions these proceedings or their impact on results of generation-related regulatory assets that are operations. recoverable through transition rates have been transferred to the distribution portion of the Environmental SurchargeFiling Affecting AEP business and are being amortized as they are and KPCo recovered through charges to regulated distribution customers. These assets are In September 2002, KPCo filed with the KPSC to classified as "transition regulatory assets . As revise its environmental surcharge tariff to recover discussed in Note 8, 'Customer Choice and the cost of emissions control equipment being Industry Restructuring the Virginia SCC ordered installed at Big Sandy Plant. See NOx the generation-related regulatory assets in the Reductions in Note 9 "Commitments and Virginia jurisdiction to remain with the generation Contingencies . portion of the business. Generation-related regulatory assets in the Virginia jurisdiction are The surcharge request, as filed, would increase being amortized concurrent with their recovery annual revenues by approximately $21 million and through capped rates. These assets are also must be approved by the KPSC before its classified as "transition regulatory assets. The inclusion in customers bills. If the KPSC does Texas jurisdiction generation-related regulatory not approve an increase in the environmental assets that are eligible for recovery through surcharge, results of operations and cash flows securitization have been classified as "regulatory would be negatively impacted. assets designated for or subject to securitization. See Note 8 "Customer Choice and Industry
- 7. Effects of Regulation: Restructuring" for further details.
In accordance with SFAS 71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) recorded in accordance with regulatory actions in orderto match expenses and revenues from cost-based rates in the same accounting period. Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries. Among other things, application of L-26
AEP s recognized regulatory assets and liabilities are comprised of the following at: December 31. 2002 2001 Cin millions) Regulatory Assets: Amounts Due From Customers For Future Income Taxes S 791 S 814 Transition Regulatory Assets 743 847 Regulatory Assets Designated for or subject to Securitization 336 959 Texas wholesale Clawback (a) 262 - Deferred Fuel Costs 143 139 unamortized Loss on Reacquired Debt 83 99 Cook Plant Restart Costs 40 80 DOE Decontamination and Decommissioning Assessment 26 31 Other 264 193 Total Regulatory Assets 52-L§ 53-162 Regulatory Liabilities: Deferred Investment Tax credits S 455 S 491 Texas Retail clawback (a) 66 - Other 419 393 Total Regulatory Liabilities L854 "394Q (a) see "Texas Restructuring section of Note 8. The recognized regulatory assets and liabilities for the registrant subsidiaries are of two types: those earning a return and those not earning a return. Items not earning a return have their recovery period end date indicated. Regulatory assets and liabilities are comprised of the following items: AEGCo APCo Recovery/ Recovery7 Refund Refund 2002 2001 Period 2002 2001 Period inthousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $209,884 $189,794 Note 1 Transition - Regulatory Assets Virginia 39,670 46,981 Jun. 2007 Transition - Regulatory Assets west Virginia 119,038 127,998 Jun. 2011 Deferred Fuel Costs 5,367 11,732 unamortized Loss on Reacquired Debt S 4,970 S 5,207 Note 2 9,147 10,421 Note 2 Deferred Storm Damage - 6 other 12 447 10.451 Note 3 Total Regulatory Assets 43j5i5 0 S Regulatory Liabilities: Deferred Investment Tax credits S52,943 $56,304 Note 4 S 33,691 S 38,328 Note 4 wv Rate Stabilization 75,601 75,601 Note 5 Amounts Due To Customers For Future Income Taxes 16,670 22,725 Note 1 other 72 112 Note 3 Total Regulatory Liabilities _9,029103 Note 1: This amount fluctuates from month to month and has no fixed recovery/refund period. Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-six years recovery period across all registrants. Note 3: other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. Note 5: Amortization will be determined by the WVPsc to offset market prices. L-27
CSPco I&M Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period (in thou isands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes ; 26,290 S 28,361 Note 1 $163,928 S171,605 Note 1 Transition - Regulatory Assets 204,961 223,830 Dec. 2008 Deferred Fuel Costs 37,501 75,002 Dec. 2003 Unamortized Loss on Reacquired Debt 5,978 7,010 Note 2 14,994 16,255 Note 2 Cook Plant Restart Costs 40,000 80,000 Dec. 2003 Incremental Nuclear Refueling Outage Expenses (Net) 29,572 2,995 Note S DOE Decontamination and Decommissioning Assessment 23,375 27, 784 Dec. 2008 Other -20.453 3.066 Note 3 38. 842 35. 286 Note 3 Total Regulatory Assets 5257,682526226Z i4IL21 k4H.Vj2 Regulatory Liabilities: Deferred Investment Tax credits ; 33,907 S 37,176 Note 4 S 97,709 $105,449 Note 4 Other 31 Note 3 65.983 52 479 Note 3 Total Regulatory Liabilities L 33,90 L 3,20 S16,62 U55792 Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-six years recovery period across all registrants. Note 3: other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. Note 5: Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage. KPCo OPCO Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes S 87,261 $83,027 Note 1 $165,106 $186,740 Note 1 Transition - Regulatory Assets 375,409 442,707 Dec. 2007 Deferred Fuel Costs - 1,542 unamortized Loss on Reacquired Debt 152 51 Note 2 4,899 5,502 Note 2 Other 14,563 13.072 Note 3 23.22 9676 Note 3 Total Regulatory Assets S SZ=L69 5 S Regulatory Liabilities: Deferred Investment Tax credits $ 9,165 $10,405 Note 4 S 18,748 S 21,925 Note 4 Other 12.152 6.551 Note 3 1,237 1.237 Note 3 Total Regulatory Liabilities S 23 19,1 Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-six years recovery period across all registrants. Note 3: other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. L-28
PSG SWEPCo Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period
- (inthousands)
Regulatory Assets: Amounts Due From Customers For Future Income Taxes $ 19.855 S 16,532 Note 1 Deferred Fuel Costs $ 76,470 S 756 Note 1 2,865 8,839 Note 1 unamortized Loss on Reacquired Debt 11,138 12,381 Note 2 17,031 20,045 Note 2 other 15.012 22.683 Note 3 12 347 15. 731 Note 3 Total Regulatory Assets L15,82_0 L 52,09 L 61,47 Regulatory Liabilities: Deferred Investment Tax Credits S 32,201 $33,992 Note 4 S 44,190 S 48,714 Note 4 AmmountS Due To Customers For Future Income Taxes 27,893 26,085 Note 1 Deferred Fuel costs 9,476 Note 1 17,226 5,487 Note 1 other 54 4.391 3 %48 22., 44 Note 3 7,094 10.889 Note 3 Total Regulatory Liabilities 1"1Z@9 68, LS LQ6,09
=10 Note 1: This amount fluctuates from month to month and has no fixed recovery/refund period.
Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-six years recovery period across all registrants. Note 3: other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. TCC TNC Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $162,247 $ 200,496 Note 1 Regulatory Assets Designated For or subject To Securitization 336,444 959,294 Note 5 Deferred Fuel Costs $26,680 $ 40,389 Note 5 Texas wholesale Clawback 262,000 - Note 5 unamortized Loss on Reacquired Debt 8,661 11,186 Note 2 3,283 8,272 Note 2 Deferred Debt Restructuring 13,324 - Note 2 10,134 - Note 2 DOE Decontamination and Decommissioning Assessment 3,170 3,170 Dec. 2004 other 9.150 _1960 Note 3 5,000 5.461 Note 3 Total Regulatory Assets SI-M-6-i"~n S45,097 S 54,122 Regulatory Liabilities: Deferred Investment Tax Credits $117,686 S 122,892 Note 4 $21,510 $ 22,781 Note 4 Deferred Fuel Costs 69,026 52,572 Note 5 Texas Retail Clawback 51,926 - Note 5 14,328 - Note 5 Over Recovery of Transition changes 20,870 - Jan. 2016 Purchased Power Conservation 9,560 - Note 1 Excess Earnings 46,111 62,852 Note 5 17,419 17,300 Note 4 Ammounts Due TO Customers For Future Income Taxes 12,280 13, 591 Note 1 other 6 6 Note 3 7. 285 5.775 Note 3 Total Regulatory Liabilities 131iU iS 3,2 Note 1: This amount fluctuates from month to month or year to year and has no fixed recovery/refund period. Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants. Note 3: other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. Note 5: Includable in TCC s and TNC s PUCT 2004 true-up proceedings. see "Texas Restructuring section of Note 8. L-29
- 8. Customer Choice and Industry for promulgation of rules for competitive retail Restructuring: electric generation service and approval of a transition plan for each electric utility company, Customer choice allowing retail customers to changed the taxation of electric companies and select alternative generation suppliers began on addressed certain major transition issues January 1, 2001 in Ohio and on January 1, 2002 including unbundling of rates and the recovery of in Michigan, Virginia and in the ERCOT area of stranded costs including regulatory assets and Texas. Customer choice in the SPP area of transition costs.
Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT. AEP s In 1999 CSPCo and OPCo filed transition plans. subsidiaries operate in both the ERCOT and SPP After negotiations with interested parties including areas of Texas. the PUCO staff, the PUCO approved a stipulation agreement for CSPCo s and OPCo s transition Implementation of legislation enacted in plans. The approved plans included, among Arkansas, Oklahoma and West Virginia to allow other things, recovery of generation-related retail customers to choose their electricity supplier regulatoryassets over seven years for OPCo and has been delayed or repealed. In 2001, over eight years for CSPCo through frozen Oklahoma delayed implementation of customer transition rates for the first five years of the choice indefinitely. In February 2003, the recovery period and through a wires charge for Arkansas General Assembly passed legislation the remaining years. At December 31, 2002, the that repealed customer choice legislation, which remaining amount of regulatory assets to be is currently awaiting signature by the Govenor of amortized as recovered was $375 million for Arkansas. Before West Virginia s choice plan can OPCo and $205 million for CSPCo. be effective, tax legislation must be passed to continue consistent funding for state and local By provisions of the Ohio Act on May 1, 2001, governments. No further legislation has been electric distribution companies became subject to introduced related to restructuring in West an excise tax based on KWH sold to Ohio Virginia. customers. The last tax year for which Ohio electric utilities paid the excise tax based on gross In general, state restructuring legislation provides receipts was May 1,2001 through April 30, 2002. for a transition from cost-based rate regulated As required by law, the gross receipts tax is paid bundled electric service to unbundled cost-based in advance of the tax year for which the utility rates for transmission and distribution service and exercises its privilege to conduct business. market pricing for the supply of electricity with CSPCo and OPCo treated the tax payment as a prepaid expense and amortized it to expense customer choice of supplier. during the privilege year. Ohio Restructuring Affecting AEP, CSPCo and The stipulation agreement also required the OPCo PUCO to consider implementation of a gross receipts tax credit rider as the parties could not Customer choice of electricity supplier and reach an agreement. Following a hearing on the restructuring began on January 1, 2001, under gross receipts tax issue, the PUCO ordered the the Ohio Act. At January 1, 2003, virtually all gross receipts tax credit rider to be effective May customers continue to receive supply service from 1, 2001 instead of May 1, 2002 as proposed by CSPCo and OPCo with a legislatively required the companies. On April 3, 2002, the Ohio residential generation rate reduction of 5%. All Supreme Court rejected the companies customers continue to be served by CSPCo and arguments and affirmed the PUCO s order which OPCo for transmission and distribution services. established the effective date of tax credit riders in rates. This ruling had no impact on 2002 The Ohio Act provided for a five-year transition results of operations as the companies had period to move from cost-based rates to market recorded an extraordinary loss ($30 million for pricing for electric generation supply services. It CSPCo and $18 million for OPCo, both amounts granted the PUCO broad oversight responsibility net of tax) in 2001. L-30
On June 27,2002, the Ohio Consumers Counsel, predict the outcome of the PUCO s investigation Industrial Energy Users Ohio and American or its impact on results of operations and Municipal Power Ohio filed a complaintwith the business practices, if any. PUCO alleging that CSPCo and OPCo have violated the PUCO s orders regarding Virginia Restructuring AffectingAEP andAPCo implementation of their transition plan and violated other applicable law by failing to In Virginia, choice of electricity supplier for retail participate in an RTO. customers began on January 1, 2002 under its restructuring law. Presently, APCo continues to The complainants seek, among other relief, an service all its previous customers under capped order from the PUCO suspending collection of rates. A finding by the Virginia SCC that an transition charges by CSPCo and OPCo until effective competitive market exists would be transfer of control of their transmission assets has required to end the transition period prior to its occurred, pricing standard offer electric scheduled end on June 30, 2007. generation effective January 1, 2006 at the market price used by the companies in their 1999 The restructuring law provides an opportunity for transition plan filings to estimate transition costs recovery of just and reasonable net stranded and imposing a $25,000 per company forfeiture generation costs. The mechanisms in the Virginia for each day AEP fails to comply with its law for net stranded cost recovery are: a capping commitment to transfer control of transmission of rates until as late as July 1, 2007, and the assets to an RTO. application of a wires charge upon customers who depart the incumbent utility in favor of an Due to the FERC s reversal of its previous alternative supplier prior to the termination of the approval of our RTO filings, CSPCo and OPCo rate cap. Capped rates are the rates in effect at have been delayed in the implementation of their July 1, 1999 if no rate change request was made RTO participation plans. We continue to pursue by the utility. APCo did not request new rates. integration of CSPCo, OPCo and otherAEP East Virginia s restructuring law does not permit the companies into PJM. Inthis regard on December Virginia SCC to change generation rates during 19, 2002, the companies filed an application with the transition period except for changes in fuel PUCO for approval of the transfer of functional costs, changes in state gross receipts taxes, or to control over certain of their transmission facilities address financial distress of the utility. to PJM. Management is unable to predict the timing of FERC s final approval of RTOs, the In July 2002, APCo filed with the Virginia SCC timing of an RTO being operational or the requesting an increase in fuel rates effective outcome of these proceedings before the PUCO. January 1, 2003. A public hearing was held on September 23, 2002 related to this filing. On In October 2002, the PUCO initiated an November 8, 2002, a decision was issued in this investigation of the financial condition of Ohio s proceeding approving an annual increase of regulated public utilities. The PUCO s goal is to approximately $24 million. identify measures available to the PUCO to ensure that the regulated operations of Ohio s The Virginia restructuring law also required filings public utilities are not impacted by adverse to be made that outline the functional separation financial consequences of parent or affiliate of generation from transmission and distribution company unregulated operations and take and a rate unbundling plan. In January 2001 appropriate corrective action, if necessary. The APCo filed its corporate separation plan and rate utilities and other interested parties were unbundling plan with the Virginia SCC. The requested to provide comments and suggestions Virginia SCC approved settlement agreements by November 12, 2002, with reply comments by that resolved most issues except the assignment November 22, 2002, on the type of information of generation related regulatory assets among necessary to accomplish the stated goals, the functionally separated generation, transmission means to gather the required information from the and distribution organizations. The Virginia SCC public utilities and potential courses of action that determined that generation related regulatory the PUCO could take. Management is unable to assets and related amortization expense should L-31
be assigned to APCo s generation function. securitization and non-bypassable wires Presently, capped rates are sufficient to recover charges; generation related regulatory assets. Therefore,
- requires reductions in NOx and sulfur dioxide management determined that recovery of APCo s emissions; generation related regulatory assets remains
- provides for an earnings test for each of the probable. APCo did not and will not collect a years 1999 through 2001 which will reduce wires charge in 2002 or 2003, respectively. The stranded cost recoveries or if there is no settlement agreements and related Virginia SCC stranded cost, provides for a refund or their order addressed functional separation leaving use to fund certain capital expenditures; decisions related to corporate separation for later
- requires each utility to structurally unbundle consideration. into a retail electric provider, a power generation company and a transmission and Texas Restructuring Affecting AEP, SWEPCo, distribution utility; TCC and TNC
- provides for certain limits for ownership and control of generating capacity by companies In preparation for the start of competition in and; Texas, CPL, SWEPCo, and WTU, the integrated electric utility companies operating in Texas, were
- provides for a 2004 true-up proceeding to required to make PUCT filings and legal and quantify and reconcile the amount of stranded operational changes to their business. AEP costs, final fuel balances, net regulatory formed new subsidiaries, Mutual Energy CPL L.P. assets, certain environmental costs, and Mutual Energy WTU L.P., to act as retail accumulated excess earnings, excess of electric providers (REP) in Texas beginning on price-to-beat revenues over market prices January 1, 2002, the effective date of customer subject to certain conditions and limitations choice in Texas. The CPL and WTU names (Retail clawback), and the difference between continued to be used by the registrant the price of power obtained through the subsidiaries which owned the generation, legislatively-mandated capacity auctions and transmission and distribution assets located in the the power costs used in the PUCT s ECOM ERCOT areas of Texas and WTU s entire model for 2002 and 2003 (Wholesale operations in SPP throughout most of 2002. In clawback) and other issues.
December 2002, WTU transferred its SPP retail customers to Mutual Energy SWEPCO L.P. AEP Underthe Texas Legislation, electric utilities were sold the new subsidiaries that serve ERCOT retail required to submit a plan to structurally unbundle customers to Centrica in December 2002, along business activities into a retail electric provider, a with the Central Power and Light and West Texas power generation company and a transmission Utilities brand names. CPL and WTU changed and distribution (T&D) utility. In 2000, SWEPCo, their names to AEP Texas Central Company TCC and TNC filed their business separation (TCC) and AEP Texas North Company (TNC), plans with the PUCT. The PUCT approved the respectively. plans for TCC and TNC but determined that competition in the SPP areas of Texas should be On January 1,2002, customer choice of electricity delayed indefinitely and abated SWEPCo s plan. supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area. All of Operations for TCC and TNC have been SWEPCo s Texas service territory and a small functionally separated consistent with the portion of TNC s service territory are located in approved plans. The delivery of electricity in the SPP. TCC operates entirely in the ERCOT ERCOT continues to be the responsibility of TCC area of Texas. and TNC at regulated prices. Texas restructuring legislation, among other Texas Legislation provides electric utilities an things: opportunity to recover regulatory assets and
- provides for the recovery of regulatory assets stranded costs resulting from the unbundling of and other stranded costs through the T&D utility from the generation facilities.
Stranded costs are the difference between L-32
regulatory net book value of generation assets costs in the final 2004 true-up proceeding and the market value of the assets based on one including the sale or exchange of generation of several methodologies authorized by the Texas assets, stock valuation or the use of an ECOM Legislation. Stranded costs can be refinanced model. through securitization (a financing structure designed to provide lower financing costs than TCC decided to obtain a market value of are available through conventional financings). generating assets for purposes of determining stranded costs for the 2004 true-up proceeding In 1999, TCC filed with the PUCT to securitize and filed a plan of divestiture with the PUCT, in $1.27 billion of its retail generation-related December 2002, seeking approval of a sales regulatory assets and $47 million in other process for all of its generating facilities. Such qualified restructuring costs. The PUCT sales quantify the actual stranded costs. The authorized the issuance of up to $797 million of amount of stranded costs under this market securitization bonds ($949 million of generation- valuation methodology will be the amount by related regulatory assets and $33 million of which net book value of TCC s generating assets, qualified refinancing costs offset by $185 million including regulatory assets and liabilities thatwere of customer benefits for accumulated deferred not securitized, exceeds the market value of the income taxes). TCC issued its securitization generation assets as measured by the net bonds in February 2002. The annual cost of the proceeds from the sale of the assets. It is bonds are recovered through a PUCT approved anticipated that any such sale will result in transition charge in distribution rates. significant stranded costs for purposes of the 2004 true-up proceeding. The filing included a TCC included regulatory assets not approved for request for the PUCT to issue a declaratory order securitization in its request for recovery of $1.1 that TCC s 25% ownership interest in its nuclear billion of stranded costs. The $1.1 billion request plant, STP, can be sold to value stranded costs. included $800 million of STP costs included in Intervenors to this proceeding, including the Property, Plant and Equipment-Electric PUCT Staff, have made filings to dismiss TCC s Production on AEP s Consolidated Balance filing claiming that the PUCT does not have the Sheets. These STP costs had previously been authority to issue a declaratory order. The identified as excess cost over market (ECOM) by intervenors also argued that the proper time to the PUCT for regulatory purposes. They were address the sales process is after the plants are earning a lower return and being amortized on an sold during the 2004 true-up proceeding. Since accelerated basis for rate-making purposes. the bidding process is not expected to be completed before mid 2004, TCC requested that After hearings on the issue of stranded costs, the the 2004 true-up proceeding be scheduled after PUCT ruled, in October 2001, that its current completion of the divestiture of the generating estimate of TCC s stranded costs was negative assets. $615 million. TCC disagreed with the ruling (see discussion of appeal ruling below). The ruling Texas Legislation also requires that electric indicated that TCC s costs were below market utilities and their affiliated power generation after securitization of regulatory assets. The final companies (PGC) sell at auction in 2002 and amount of TCC s stranded costs including 2003 at least 15% of the PGC s Texas regulatory assets and ECOM will be established jurisdictional installed generation capacity in by the PUCT in the 2004 true-up proceeding. If order to promote competitiveness in the TCC s total stranded costs determined in the wholesale market through increased availability of 2004 true-up are less than the amount of generation and liquidity. Actual market power securitized regulatory assets, the PUCT can prices received in the state mandated auctions wil implement an offsetting credit to transmission and replace the PUCT s earlier estimates of those distribution rates. market prices used in the ECOM model to calculate the stranded cost for the 2004 true-up The Texas Legislation allows for several proceeding. alternative methods to be used to value stranded L-33
The decision to determine stranded costs using none for TCC) were recorded prior to September market prices, instead of using the PUCT s 30, 2002. The PUCT s final order regarding 2001 ECOM model estimates, enabled TCC to record a excess earnings required only minor adjustments $262 million regulatory asset and related to prior estimates. revenues which represents the quantifiable amount of stranded costs for the year 2002 Due to TCC s and TNC s disagreement with the related to the wholesale prices. Prior to the PUCT s final order for the 2000 excess earnings, decision to pursue a sale of TCC s generating the companies filed an appeal in district court in assets, the PUCT s ECOM estimate prohibited 2001 seeking judicial review of the PUCT s the recognition of the regulatory assets and determination of excess earnings. The district revenues as there was no way to quantify court upheld the PUCT s order and the stranded costs. As discussed above, a defined companies appealed that decision. A ruling on process is required in order to determine the the appeal is expected in 2003. amount of stranded costs related to generation facility for the 2004 true-up proceedings. TCC s On January 28, 2003, the TCC and TNC filed an plan of divestiture filed with the PUCT during appeal in District Court seeking judicial review of December 2002 provided such a process. the PUCT order for the 2001 excess earnings. When the divestiture and the 2004 true-up The PUCT ruled that prior to the 2004 true-up processing is completed, TCC will securitize stranded costs which exceed current securitized proceeding, no adjustments would be made to the amounts. The annual costs of securitization will amount of stranded costs authorized by the PUCT be recovered through a non-bypassable rate to be securitized. Final stranded cost amounts surcharge bythe regulated T&D utilityoverthe life and the treatment of excess earnings will be of the securitization bonds. Any stranded costs determined in the 2004 true-up proceeding. To and other true-up amounts not recovered through the extent that the final 2004 true-up proceeding the sale of securitization bonds maybe recovered determines that TCC should recover additional through a separate non-bypassable competitive stranded costs, the additional amount recoverable transition charge to T&D utility customers. can also be securitized. The PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through distribution rates to The Texas Legislation provides for an earnings the extent of any over-mitigation of stranded costs test each year 1999 through 2001 and requires represented by negative ECOM. In 2001 the PUCT approval of the annual earnings test PUCT issued an order requiring TCC to reduce calculation. distribution rates by approximately $54.8 million plus accrued interest over a five-year period The PUCT issued final orders for the 1999 beginning January 1, 2002 in order to return earnings test in February 2001 and for the 2000 estimated excess earnings for 1999, 2000 and earnings test in September 2001. The 1999 2001. Since excess earnings amounts were excess earnings were none for SWEPCo, $24 expensed in 1999, 2000 and 2001, the order has million for TCC and $1 million for TNC. Excess no additional effect on reported net income but earnings for 2000 were $1 million for SWEPCo, will reduce cash flows for the five year refund
$23 million for TCC and $17 million for TNC. period. The amount to be refunded is recorded as Adjustments were recorded in results of a regulatory liability.
operations as the orders were received. Management believes that TCC will have The PUCT issued its final order for the 2001 stranded costs in 2004. TCC has appealed the earnings test in December 2002. An estimate of PUCT s refund of excess earnings to the Travis 2001 excess earnings of $8 million for TCC, $2 County District Court and, depending on the million for SWEPCo and none for TNC had been outcome of that appeal (and the final outcome of recorded in 2001. Adjustments to reflect the the rulemaking challenge discussed below), the PUCT staffs estimate of excess earnings ($2 PUCT may revise the treatment of excess million for SWEPCo, $0.7 million for TNC and earnings in the final calculation of the stranded L-34
cost balance. In the same appeal, TCC and Under the Texas Legislation, retail electric certain unaffiliated parties also challenged various providers (REPs) associated with integrated elements of the PUCT s order determining the utilities are required to offer residential and small estimated stranded costs of TCC, with the commercial customers (with a peak usage of less unaffiliated parties contending, among other than 1000 KW) a price-to-beat rate until January things, that the entire $615 million of negative 1, 2007. In December 2001 the PUCT approved stranded costs should be refunded presently. price-to-beat rates for the AEP REPs in TCC s Prior to the Court hearing on this issue, however, and TNC s ERCOT area. Customers with a peak TCC agreed to give up its claims concerning usage of more than 1000 KW are subject to errors in the calculation of the stranded cost market rates. The Texas Restructuring Legislation estimate, while the unaffiliated parties agreed to also provides that a REP associated with give up claims that there should be a refund of integrated utilities may request an adjustment of negative stranded costs. The Travis County its fuel portion of the price-to-beat rate up to two District Court subsequently heard oral arguments times annually to reflect changes in market prices concerning the remaining issues in the appeal, of fuel and purchased energy costs based upon but has not yet issued a decision. The PUCT s changes in NYMEX gas prices. stranded cost estimate that is the subject of this appeal will be superceded by a final determination As part of the 2004 true-up proceedings the price-of stranded costs to be accomplished as part of to-beat rates charged byAEP REPs for 2002 and the 2004 true-up proceeding. 2003 will be compared to the market rates for the same period. If market rates are lower, the In a separate appeal challenging the PUCT s excess of the price-to-beat, reduced by non-substantive rule governing the 2004 true-up bypassable delivery charges, over the prevailing proceeding, the Texas Third Court of Appeals market prices must be returned to the distribution ruled in February 2003, that the Texas Legislation company, subject to a per customer maximum. does not contemplate the refunding of negative During 2002, AEP provided for such potential stranded costs to customers. The Court of liabilities at the maximum amount via a charge to Appeals held that the PUCT was justified in using revenues, and recorded a regulatory liability for any negative stranded cost balance determined in TCC and TNC. These amounts were $52 million the 2004 true-up proceeding only as an offset to forTCC and $14 million for TNC. prevent an over-recovery of stranded costs via securitization. In addition, the Court of Appeals West Virginia Restructuring Affecting AEP and ruled that negative stranded costs cannot be APCo offset against other true-up balances, including final under-recovered fuel amounts. This ruling In 2000 the WVPSC issued an order approving may be further appealed to the Supreme Court of an electricity restructuring plan which the WV Texas. Legislature approved byjoint resolution. The joint resolution provides that the WVPSC cannot Beginning January 1, 2002, fuel costs are not implement the plan until the legislature makes tax subject to PUCT fuel reconciliation proceedings law changes necessary to preserve the revenues for TCC and TNC s ERCOT retail customers. of state and local governments. Since the WV Due to the delay of competition for SWEPCo s Legislature has not passed the required tax law SPP area of Texas, SWEPCo continues to record changes, the restructuring plan has not become effective. AEP subsidiaries, APCo and WPCo, and request recovery of fuel costs subject to provide electric service in WV. Texas fuel proceedings. Final deferred fuel balances related to ERCOT customers of TCC A Joint Stipulation approved by the WVPSC in and TNC at December 31, 2001 will be included 2000 in connection with a base rate filing, allowed in the 2004 true-up proceeding. If the final fuel for recovery of regulatory assets including any balances or any amount incurred but not yet generation-related regulatory assets through the reconciled are not recovered, they could have a following provisions: negative impact on results of operations.
- Frozen transition rates and a wires charge of 0.5 mills per KWH.
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- The retention, as a regulatory liability, on the Discontinuance of the Application of SFAS 71 books of a net cumulative deferred ENEC RegulatoryAccountinginArkansas, Ohio, Texas, over-recovery balance of $66 million to be Virginia and West Virginia AffectingAEP, APCo, used to offset the cost of deregulation when CSPCo, OPCo, SWEPCo, TCC and TNC generation is deregulated in WV.
- The retention of net merger savings prior to The enactment of restructuring legislation and the December 31, 2004 resulting from the ability to determine transition rates, wires charges merger of AEP and CSW. and any resultant gain or loss under restructuring
- A 0.5 mills per KWH wires charge for legislation in Arkansas, Ohio, Texas, Virginia and departing customers provided for in the WV West Virginia resulted in AEP and certain Restructuring Plan. subsidiaries discontinuing regulatory accounting under SFAS 71 for the generation portion of their Management expects that the approved Joint business in those states. Under the provisions of Stipulation provides for the recovery of existing SFAS 71, regulatory assets and regulatory regulatory assets and other stranded costs. liabilities are recorded to reflect the economic effects of regulation by matching expenses with In order for customer choice to become effective related regulated revenues.
in WV, the WV Legislature needed to enact additional legislation to preserve the revenues of The discontinuance of the application of SFAS 71 state and local government. In the subsequent in Arkansas, Ohio, Texas, Virginia and West two legislative sessions, which usually end in Virginia resulted in recognition of extraordinary March each year, the West Virginia Legislature gains or losses. The discontinuance of SFAS 71 has not enacted the required legislation. Due to can require the write-off of regulatory assets and the lack of legislative activity, the WVPSC closed liabilities related to the deregulated operations, two proceedings related to electricity restructuring unless their recovery is provided through cost-in the summer of 2002. based regulated rates to be collected in a portion of operations which continues to be rate The two closed proceedings related to the regulated. Additionally, a company must respective dockets intended originally to determine if any plant assets are impaired when determine whether West Virginia should they discontinue SFAS 71 accounting. At the deregulate the generation business, and to time the companies discontinued SFAS 71, the develop the WVPSC s Deregulation Plan and analysis showed that there was no accounting related rules to implement the Plan. impairment of generation assets. Management has reviewed these two As a result of deregulation of generation, the proceedings and has concluded that at this time it application of SFAS 71 for the generation portion is not clear that APCo meets the requirements to of the business in Arkansas, Ohio, Texas, Virginia reapply SFAS 71. Management will monitor and West Virginia was discontinued. Remaining developments to determine when it is appropriate generation-related regulatory assets will be to reapply SFAS 71 to APCo s generation amortized as they are recovered under terms of business. transition plans. Management believes that substantially all generation-related regulatory Arkansas Restructuring Affecting AEP and assets and stranded costs will be recovered SWEPCo under terms of the transition plans. If future events including the 2004 true-up proceeding in In 1999, Arkansas enacted legislation to Texas were to make their recovery no longer restructure its electric utility industry. probable, the companies would write-off the portion of such regulatory assets and stranded In February 2003, the Arkansas General costs deemed unrecoverable as a non-cash Assembly passed legislation that repealed extraordinary charge to earnings. If any write-off customer choice legislation, which is currently of regulatory assets or stranded costs occurred, it awaiting signature by the Governor of Arkansas. could have a material adverse effect on future L-36
results of operations, cash flows and possibly regulatory approval to build a new high voltage financial condition. transmission line for over a decade. Certificates have been issued by both the West Virginia Michigan Restructuring - Affecting AEP and l&M Public Service Commission and the Virginia State Corporation Commission authorizing construction Customer choice commenced forl&M s Michigan and operation of the line. On December 31, customers on January 1,2002. Effective with that 2002, the U.S. Forest Service issued a final date the rates on l&M s Michigan customers bills environmental impact statement and record of for retail electric service were unbundled to alloy/ decision to allow the use of federal lands in the customers the opportunity to evaluate the cost of Jefferson National Forest for construction of a generation service for comparison with other portion of the line. We expect additional state offers. I&M s total rates in Michigan remain and federal permits to be issued in the first half of unchanged and reflect cost of service. At 2003. Through December 31, 2002, we had December 31, 2002, none of l&M s customers invested approximately $51 million in this effort. have elected to change suppliers and no The line is estimated to cost $287 million alternative electric suppliers are registered to including amounts spent to date with completion compete in l&M s Michigan service territory. scheduled in 2006. If the required permits are not obtained and the line is not constructed, the $51 Management has concluded that as of December million investment would be written off adversely 31, 2002 the requirements to apply SFAS 71 affecting future results of operations and cash continue to be met since l&M s rates for flows. generation in Michigan continue to be cost-based regulated. Long-term contracts to acquire fuel for electric generation have been entered into for various
- 9. Commitments and Contingencies: terms, the longest of which extends to the year 2014 for the AEP System. The expiration date of Construction and Other Commitments Affecting the longest fuel contract is 2007 for APCo, 2005 AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, for CSPCo, 2007 for l&M, 2005 for KPCo, 2012 PSO, SWEPCo, TCC and TNC for OPCo, 2014 for PSO, 2006 for SWEPCo and 2006 for TNC. The contracts provide for periodic The AEP System has substantial construction price adjustments and contain various clauses commitments to support its operations. Aggregate that would release the subsidiaries from their construction expenditures for 2003-2005 for obligations under certain force majeure consolidated domestic and foreign operations are conditions.
estimated to be $4.7 billion. The AEP System has unit contingent contracts to The following table shows the estimated supply approximately 250 MW of capacity to construction expenditures of the subsidiary unaffiliated entities through December 31, 2009. registrants for 2003 2005: The commitment is pursuant to a unit power agreement requiring the delivery of energy only if (in millions) the unit capacity is available. AEGCo $ 70.9 APCo 1,005.7 Power Generation Facility Affecting AEP and CS PCO 418.9 OPCo I&M 601.5 KPCo 148.3 OPCo 733.4 AEP has entered into agreements with Katco Pso 262.3 Funding L.P. (Katco) an unrelated unconsolidated SWEPCO 351.3 special purpose entity. Katco has an aggregate TCC 419.6 TNC 130.8 financing commitment of $525 million and a capital structure of which 3% is equity from APCo, AEP s subsidiary which operates in investors with no relationship to AEP or any of its Virginia and West Virginia, has been seeking subsidiaries and 97% is debt from a syndicate of L-37
banks. Katco was formed to develop, construct, As of December 31,2002, project costs subject to finance and lease a power generation facility to these agreements totaled $360 million, and total AEP. Katco will own the power generation facility costs for the completed facility are expected to be and lease it to AEP after construction is approximately $510 million. For the 30 year completed. The lease will be accounted for as an extended lease term, the lease rental is a variable operating lease (see Note 22), therefore neither rate obligation indexed to three-month LIBOR. the facility nor the related obligations are reported Consequently as market interest rates increase, on AEP s balance sheet. Payments under the the payments under this operating lease will also operating lease are expected to commence in the increase. Annual payments of approximately$12 first quarter of 2004. AEP will in turn sublease the million represent future minimum payments during facility to Dow Chemical Company (DOW), which the initial term calculated using the indexed will use the energy produced by the facility and LIBOR rate (1.38% at December 31, 2002). The sell excess energy. AEP has agreed to purchase Power Generation Facility collateralizes the debt the excess energy from DOW for resale. The use obligation of Katco. AEP s maximum exposure to of Katco allows AEP to limit its risk associated loss as a result of its involvement with Katco is with the power generation facility once the 100% during the construction phase and up to construction phase has been completed. 82% once the construction is completed. Maximum loss isdeemed to be remote due to the AEP is the construction agent for Katco, and is collateralization. responsible for completing construction by December 31,2003, subject to unforeseen events It is reasonably possible that AEP will consolidate beyond AEP s control. Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 In the event the project is terminated before "Consolidation of Variable Interest Entities (FIN completion of construction, AEP has the option to 46). Upon consolidation, AEP would record the either purchase the facility for 100% of project assets, liabilities, depreciation expense, minority costs or terminate the project and make a interest and debt interest expense. AEP would payment to Katco for 89.9% of project costs. eliminate operating lease expense. The sublease to DOW would not be affected by this The operating lease between Katco and AEP consolidation. commences on the commercial operation date of the facility and continues until November 2006. OPCo has entered into a 30-year power purchase The lease contains extension options subject to agreement for electricity produced by an the approval of Katco, and if all extension options unaffiliated entitys three-unit natural gas fired were exercised, the total term of the lease would plant. The plant was completed in 2002 and the be 30 years. AEP s lease payments to Katco are agreement will terminate in 2032. Under the sufficient for Katco to make required debt terms of the agreement, OPCo has the option to payments and provide a return to the investors of run the plant until December 31, 2005 taking Katco. At the end of each lease term, AEP may 100% of the power generated and making renew the lease at fair market value subject to monthly capacity payments. The capacity Katco s approval, purchase the facility at its payments are fixed through December 2005 at original construction cost, or sell the facility, on $1.2 million per month. For the remainder of the behalf of Katco, to an independent third party. If 30-year contract term, OPCo will pay the variable the facility is sold and the proceeds from the sale costs to generate the electricity it purchases (up are insufficient to repay Katco, AEP may be to 20% of the plants capacity). required to make a payment to Katco for the difference between the proceeds from the sale Nuclear Plants Affecting AEP, I&M and TCC and the obligations of Katco, up to 82% of the projects cost. AEP has guaranteed a portion of l&M owns and operates the two-unit 2,110 MW the obligations of its subsidiaries to Katco during Cook Plant under licenses granted by the NRC. the construction and post-construction periods. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint L-38
owners under licenses granted by the NRC. The prolonged accidental outage. I&M and STPNOC operation of a nuclear facility involves special utilize an industry mutual insurer for the risks, potential liabilities, and specific regulatory placement of this insurance coverage. and safety requirements. Should a nuclear Participation in this mutual insurer requires a incident occur at any nuclear power plant facility contingent financial obligation of up to $36 million in the U.S., the resultant liability could be for l&M and $3 million for TCC which is substantial. By agreement I&M and TCC are assessable if the insurers financial resources partially liable together with all other electric utility would be inadequate to pay for losses. companies that own nucleargenerating units fora nuclear power plant incident at any nuclear plant The current Price-Anderson Act expired in August in the U.S. Inthe event nuclear losses or liabilities 2002. Its contingent financial obligations still are underinsured or exceed accumulated funds apply to reactors licensed by the NRC as of its and recovery from customers is not possible, expiration date. It is anticipated that the Price-results of operations, cash flows and financial Anderson Act will be renewed with increased third condition would be adversely affected. party financial protection requirements for nuclear incidents. Nuclear Incident Liability Affecting AEP, I&M and TCC SNF Disposal Affecting AEP, I&M and TCC The Price-Anderson Act establishes insurance Federal law provides for government protection for public liability arising from a nuclear responsibility for permanent SNF disposal and incident at $9.5 billion and covers any incident at assesses nuclear plant owners fees for SNF a licensed reactor in the U.S. Commercially disposal. A fee of one mill per KWH for fuel available insurance provides $200 million of consumed after April 6, 1983 at Cook Plant and coverage. In the event of a nuclear incident at STP is being collected from customers and any nuclear plant in the U.S., the remainder of the remitted to the U.S. Treasury. Fees and related liability would be provided by a deferred premium interest of $224 million for fuel consumed prior to assessment of $88 million on each licensed April 7, 1983 at Cook Plant have been recorded reactor in the U.S. payable in annual installments as long-term debt. I&M has not paid the of $10 million. As a result, I&M could be government the Cook Plant related pre-April 1983 assessed $176 million per nuclear incident fees due to continued delays and uncertainties payable in annual installments of $20 million. TCC related to the federal disposal program. At could be assessed $44 million per nuclear December 31, 2002, funds collected from incident payable in annual installments of $5 customers towards payment of the pre-April 1983 million as its share of a STPNOC assessment. fee and related earnings thereon are in external The number of incidents for which payments funds and exceed the liability amount. TCC is not could be required is not limited. Under an liable for any assessments for nuclear fuel industry-wide program insuring workers at nuclear consumed prior to April 7, 1983 since the STP facilities, I&M and TCC are also obligated for units began operation in 1988 and 1989. assessments of up to $6.2 million and $1.6 million, respectively, for potential claims. These Decommissioning and Low Level Waste obligations will remain in effect until December Accumulation Disposal Affecting AEP, I&M and 31, 2007. TCC Insurance coverage for property damage, Decommissioning costs are accrued over the decommissioning and decontamination at the service lives of the Cook Plant and STP. The Cook Plant and STP is carried by l&M and licenses to operate the two nuclear units at Cook STPNOC in the amount of $1.8 billion each. I&I'M Plant expire in 2014 and 2017. After expiration of and STPNOC jointly purchase $1 billion of excess the licenses, Cook Plant is expected to be coverage for property damage, decommissioning decommissioned using the prompt and decontamination. Additional insurance decontamination and dismantlement (DECON) provides coverage for extra costs resulting from a method. The estimated cost of decommissioning L-39
and low level radioactive waste accumulation On the AEP Consolidated Balance Sheets, disposal costs for Cook Plant ranges from $783 nuclear decommissioning trust assets are million to $1,481 million in 2000 nondiscounted included in Other Assets and a corresponding dollars. The wide range is caused by variables in nuclear decommissioning liability is included in assumptions including the estimated length of Other Noncurrent Liabilities. On TCC s balance time SNF may need to be stored at the plant site sheets, the nuclear decommissioning liability of subsequent to ceasing operations. This, in tum, $98 million is included in Electric Utility Plant-depends on future developments in the federal Accumulated Depreciation and Amortization. government's SNF disposal program. Continued The decommissioning liability for both nuclear delays in the federal fuel disposal program can plants combined totals $719 million and $699 result in increased decommissioning costs. I&M million at December 31, 2002 and 2001, is recovering estimated Cook Plant respectively. decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the Federal EPA Complaint and Notice of Violation range in the most recent decommissioning study Affecting AEP, APCo, CSPCo, I&M, and OPCo at the time of the last rate proceeding. The amount recovered in rates for decommissioning Since 1999 AEPSC, APCo, CSPCo, I&M, and the Cook Plant and deposited in the external fund OPCo have been involved in litigation regarding was $27 million in 2002 and 2001 and $28 million generating plant emissions under the Clean Air in 2000. Act. Federal EPA and a number of states alleged that AEP System companies and eleven The licenses to operate the two nuclear units at unaffiliated utilities modified certain units at coal STP expire in 2027 and 2028. After expiration of fired generating plants in violation of the Clean Air the licenses, STP is expected to be Act. Federal EPA filed complaints against AEP decommissioned using the DECON method. TCC subsidiaries in U.S. District Court forthe Southern estimates its portion of the costs of District of Ohio. A separate lawsuit initiated by decommissioning STP to be $289 million in 1999 certain special interest groups was consolidated nondiscounted dollars. TCC is accruing and with the Federal EPA case. The alleged modification of the generating units occurred over recovering these decommissioning costs through a 20 year period. rates based on the service life of STP at a rate of
$8 million per year. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an Decommissioning costs recovered from emissions increase, permitting requirements customers are deposited in external trusts. In might be triggered and the plant may be required 2002 and 2001 I&M deposited in its to install additional pollution control technology.
decommissioning trust an additional $12 million This requirement does not apply to activities such each year related to special regulatory as routine maintenance, replacement of degraded commission approved funding for equipment or failed components, or other repairs decommissioning of the Cook Plant. Trust fund needed for the reliable, safe and efficient earnings increase the fund assets and the operation of the plant. The Clean Air Act recorded liability and decrease the amount authorizes civil penalties of up to $27,500 per day needed to be recovered from ratepayers. per violation at each generating unit ($25,000 per Decommissioning costs including interest, day prior to January 30, 1997). In 2001 the unrealized gains and losses and expenses of the District Court ruled claims for civil penalties based trust funds are recorded in Other Operation on activities that occurred more than five years expense for Cook Plant. For STP, nuclear before the filing date of the complaints cannot be decommissioning costs are recorded in Other imposed. There is no time limit on claims for Operation expense, interest income of the trusts injunctive relief. are recorded in Nonoperating Income and interest expense of the trust funds are included in Interest Management believes its maintenance, repair and Charges. replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its L40
= - defense. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to Management is unable to estimate the loss or allocate allowances and project growth for both range of loss related to the contingent liability for the NOx Rule and the Section 126 Rule. AEP civil penalties under the ClearAirAct proceedings subsidiaries and other utilities requested that the and unable to predict the timing of resolution of D.C. Circuit Court vacate the Section 126 Rule or these matters due to the number of alleged suspend its May 2003 compliance date. In violations and the significant numberof issues yet August 2001 the D.C. Circuit Court issued an to be determined by the Court. In the event the order tolling the compliance schedule until AEP System companies do not prevail, any Federal EPA responded to the Court s remand. capital and operating costs of additional pollution On April 30, 2002, Federal EPA announced that control equipment that may be required as well as May 31, 2004 is the compliance date for the any penalties imposed would adversely affect Section 126 Rule. Federal EPA published a future results of operations, cash flows and notice in the Federal Register in May 2002 possibly financial condition unless such costs can advising that no changes in the growth factors be recovered through regulated rates and market used to set the NOx budgets were warranted. In prices for electricity. June 2002 AEP subsidiaries joined other utilities and industrial organizations in seeking a review of In December 2000 Cinergy Corp., an unaffiliated Federal EPA s action in the D.C. Circuit Court. utility, which operates certain plants jointly owned This action is pending. by CSPCo, reached a tentative agreement with the Federal EPA and other parties to settle In 2000 the Texas Commission on Environmental litigation regarding generating plant emissions Quality (formerly the Texas Natural Resource under the Clean Air Act. Negotiations are Conservation Commission) adopted rules continuing between the parties in an attempt to requiring significant reductions in NOx emissions reach final settlement terms. Cinergy s settlement from utility sources, including SWEPCo and TCC. could impact the operation of Zimmer Plant and The compliance date is May 2003 for TCC and W.C. Beckjord Generating Station Unit 6 (owned May 2005 for SWEPCo. 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be AEP is installing a variety of emission control unable to determine the settlement s impact on its technologies to reduce NOx emissions to comply jointly owned facilities and its results of operations with the applicable state and Federal NOx and cash flows. requirements. This includes selective catalytic reduction (SCR) technolocy on certain units and NOx Reductions Affecting AEP, AEGCo, APCo, non-SCR technologies on a larger number of CSPCo, I&M, KPCo, OPCo, SWEPCo and TCC units. During 2001 SCR technology commenced operations on OPCo s Gavin Plant. Installation of Federal EPA issued a NOx Rule requiring SCR technology on Amos and Mountaineer plants substantial reductions in NOx emissions in a was completed and commenced operation in number of eastern states, including certain states May 2002. Construction of SCR technology at in which the AEP System s generating plants are certain other AEP generating units continues. located. The NOx Rule has been upheld on Non-SCR technologies have been installed and appeal. The compliance date for the NOx Rule is commenced operation on a number of units May 31, 2004. across the AEP System and additional units will be equipped with these technologies. In2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by The AEP NOx compliance plan is a dynamic plan certain northeastern states under the Clean Air that is continually reviewed and revised as new Act. The rule imposed emissions reduction information becomes available on the requirements comparable to the NOx Rule performance of installed technologies and the beginning May 1, 2003, for most of AEP s coal- cost of planned technologies. Certain compliance fired generating units. Affected utilities, including steps may or may not be necessary as a result of certain AEP operating companies, petitioned the this new information. Consequently, the plan has D.C. Circuit Court to review the Section 126 Rule. a range of possible outcomes. Our current L-41
estimates indicate that compliance with the NOx Missouri and also met the PUCHAs single region Rule, the Texas Commission on Environmental requirement because it is now technically possible Quality rule and the Section 126 Rule could result to centrally control the output of power plants in required capital expenditures in the range of across many states. In its ruling, the appeals $1.3 billion to $2 billion of which $843 million has court said that the SEC failed to support and been spent through December 31, 2002 for the explain its conclusions that the integration and AEP System. The range of cost estimate reflects single region requirements are satisfied. the uncertainty over the need for certain SCR projects. Estimated compliance cost ranges and Management believes that the merger meets the amounts spent by registrant subsidiaries at requirements of the PUHCA and expects the December 31, 2002, are as follows: matter to be resolved favorably. Estimated IAmount Enron Bankruptcy Affecting AEP, APCo, compliance Costs Spent CSPCo, I&M, KPCo and OPCo (in millions) AEGCo $30 198 $ 1 On October 15,2002, certain subsidiaries of AEP APCo 445 234 filed claims against Enron and its subsidiaries in CSPCo 93 45 the bankruptcy proceeding filed by the Enron I&M 42 210 5 entities which are pending in the U.S. Bankruptcy KPCo 163 135 Court for the Southern District of New York. At the OPCo 535 864 387 date of Enron s bankruptcy AEP had open trading SWEPCO 40 24 contracts and trading accounts receivables and TCC 5 5 payables with Enron. In addition, on June 1, Since compliance costs cannot be estimated with 2001, we purchased Houston Pipe Line Company certainty, the actual cost to comply could be (HPL) from Enron. Various HPL related significantly different than the estimates contingencies and indemnities remained depending upon the compliance alternatives unsettled at the date of Enron s bankruptcy. The selected to achieve reductions in NOx emissions. timing of the resolution of the claims by the Unless any capital and operating costs of Bankruptcy Court is not certain. additional pollution control equipment are recovered from customers, they will have an In connection with the 2001 acquisition of HPL, adverse effect on results of operations, cash we acquired exclusive rights to use and operate flows and possibly financial condition. the underground Bammel gas storage facility pursuant to an agreement with BAM Lease MergerLitigation -AffectingAEPAPCo, CSPCo, Company, a now-bankrupt subsidiary of Enron. I&M, KPCo, OPCo, PSO, SWEPCo, TCC and This exclusive right to use the referenced facility TNC is for a term of 30 years, with a renewal right for another 20 years and includes the use of the On January 18, 2002, the U.S. Court of Appeals Bammel storage reservoir and the related for the District of Columbia ruled that the SEC compression, treating and delivery systems. We failed to prove that the June 15, 2000 merger of have engaged in preliminary discussions with AEP with CSW meets the requirements of the Enron concerning the possible purchase of the PUHCA and sent the case back to the SEC for residual interest held by Enron in the Bammel further review. Specifically, the court told the SEC storage facility and the possible resolution of to revisit its conclusion that the merger met outstanding issues between AEP and Enron PUHCA requirements that utilities be "physically relating to our acquisition of its interest in the interconnected and confined to a "single area or Bammel storage facility. We are unable to predict region. whether these discussions will lead to an agreement on these subjects. If these In its June 2000 approval of the merger, the SEC agreed with AEP that the companies systems are discussions do not lead to an agreement, there integrated because they have transmission may be a dispute with Enron concerning our access rights to a single high-voltage line through ability to continue utilization of the Bammel storage facility under the existing agreement. L-42
We also entered into an agreement with BAM analysis of the HPL related purchase Lease Company which grants HPL the right to contingencies and indemnifications. use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation Enron has recently instituted proceedings against of the Bammel gas storage facility. The Bammel other energy trading counter-parties challenging Gas Trust, which purportedly owned the practice of utilizing offsetting receivables and approximately 55 billion cubic feet of the gas, had payables and related collateral across various entered into a financing arrangement in 1997 with Enron entities. We believe that we have the right Enron and a group of banks. These banks to utilize similar procedures in dealing with purported to have certain rights to the gas in payables, receivables and collateral with Enron certain events of default. In connection with entities by offsetting approximately $110 million of AEP s acquisition of HPL, the banks entered into trading payables owed to various Enron entities an agreement granting HPL s use of the cushion against trading receivables due to us. We believe gas and released HPL from liabilities and we have legal defenses to any challenge that may obligations under the financing arrangement. be made to the utilization of such offsets but at HPL was thereafter informed by the banks of a this time are unable to predict the ultimate purported default by Enron under the terms of the resolution of this issue. referenced financing arrangement. In July 2002 the banks filed a lawsuit against HPL seeking a Shareholder Lawsuits - Affecting AEP declaratory judgment that they have a valid and enforceable security interest in this cushion gas In the fourth quarter of 2002 lawsuits alleging which would permit them to cause the withdrawal securities law violations and seeking class action of this gas from the storage facility. In September certification were filed in federal District Court, 2002 HPL filed a general denial and certain Columbus, Ohio against AEP, certain AEP counterclaims against the banks. Management is executives, and in some of the lawsuits, members unable to predict the outcome of this lawsuit or its of the AEP Board of Directors and certain impact on results of operations and cash flows. investment banking firms. The lawsuits claim that AEP failed to disclose that alleged "round trip In 2001 AEP expensed $47 million ($31 million trades resulted in an overstatement of revenues, net of tax) for our estimated loss from the Enron that AEP failed to disclose that AEP traders bankruptcy. In2002 AEP expensed an additional falsely reported energy prices to trade $6 million for a cumulative loss of $53 million publications that published gas price indices and ($34 million net of tax). The amounts for certain that AEP failed to disclose that it did not have in subsidiary registrants were: place sufficient management controls to prevent round trip trades or false reporting of energy Amounts prices. The plaintiffs seek recovery of an Amounts Net of unstated amount of compensatory damages, Registrant Expensed Tax attorney fees and costs. The cases are presently (in millions) pending a decision by the Court on competing motions by certain plaintiffs and groups of APCo $5.3 $3.4 plaintiffs for designation as lead plaintiff. Once CSPCo 2.7 1.8 the Court selects a lead plaintiff, that lead plaintiff I&M 2.8 1.8 will file an amended complaint. AEP intends to KPCO 1.1 0.7 vigorously defend against these actions. Also in OPCo 3.6 2.3 the fourth quarter of 2002, two shareholder derivative actions were filed in state court in The additional 2002 expense did not materially Columbus, Ohio against AEP and its Board of change the cumulative expense per registrant Directors alleging a breach of fiduciary duty for subsidiary. The amounts expensed were based failure to establish and maintain adequate internal on an analysis of contracts where AEP and Enron controls over AEP s gas trading operations; and, entities are counterparties, the offsetting of a lawsuit was filed against AEP, certain AEP receivables and payables, the application of executives and AEP s ERISA Plan Administrator deposits from Enron entities and managements L-43
in federal District Court for the Southern District of Energy Market Investigations Affecting AEP New York (subsequently transferred to federal District Court in Columbus, Ohio) alleging In February 2002, the FERC issued an order violations of the Employee Retirement Income directing its Staff to conduct a fact-finding Security Act in the selection of AEP stock as a investigation into whether any entity, including investment alternative and in the allocation of Enron, manipulated short-term prices in electric assets to AEP stock. These cases are in the energy or natural gas markets in the West or initial pleading stage. AEP intends to vigorously otherwise exercised undue influence over defend against these actions. wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP California Lawsuit Affecting AEP furnished certain information to the FERC in response to their related data request. In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a lawsuit in Los Pursuant to the FERC s February order, on May Angeles County, California Superior Court against 8, 2002, the FERC issued further data requests, forty energy companies including AEP and two including requests for admissions, with respect to publishing companies alleging violations of certain trading strategies engaged in by Enron California law through alleged fraudulent reporting and, allegedly, traders of other companies active of false natural gas price and volume information in the wholesale electricity and ancillary services with an intent to affect the market price of natural markets in the West, particularly California, during gas and electricity. This case is in the initial the years 2000 and 2001. This data requestwas pleading stage. AEP intends to vigorously defend issued to AEP as part of a group of over 100 against this action. entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to Arbitration of Williams Claim Affecting AEP the California Independent System Operator and/or the California Power Exchange. In October 2002, AEP filed its demand for arbitration with the American Arbitration The May 8, 2002 FERC data request required Association to initiate formal arbitration senior management to conduct an investigation proceedings in a dispute with the Williams into our trading activities during 2000 and 2001 Companies (Williams). The proceeding results and to provide an affidavit as to whether we from Williams repudiation of its obligations to engaged in certain trading practices that the provide physical power deliveries to AEP and FERC characterized in the data request as being Williams failure to provide the monetary security potentially manipulative. Senior management required for natural gas deliveries by AEP. complied with the order and denied our Consequently, both parties claimed default and involvement with those trading practices. terminated all outstanding natural gas and electric power trading deals among the various Williams On May 21,2002, the FERC issued afurther data and AEP affiliates. Williams claimed that AEP request with respect to this matter to us and over owes approximately $130 million in connection 100 other market participants requesting with the termination and liquidation of all trading information for the years 2000 and 2001 deals. AEP believes it has valid claims arising concerning "wash , "round trip or "sale/buy back from Williams actions and is seeking, in part, a trading in the Western System Coordinating determination that either no amount is due or that Council (WSCC), which involves the sale of an a lesser amount is due from AEP to Williams electricity product to another company together (which is fully reserved by AEP) and the extent of with a simultaneous purchase of the same any other damages and legal or equitable relief product at the same price (collectively, "wash available. Although management is unable to sales ). Similarly, on May 22, 2002, the FERC predict the outcome of this matter, it is not issued an additional data request with respect to expected to have a material impact on results of this matter to us and other market participants operations, cash flows or financial condition. requesting similar information for the same period with respect to the sale of natural gas products in L-44
= - the WSCC and Texas. After reviewing our 2002. records, we responded to the FERC that we did not participate in any 'Wash sale transactions In October 2002, AEP dismissed several involving power or gas in the relevant market. We employees involved in natural gas marketing and further informed the FERC that certain of our trading after the Company determined that they traders did engage in trades on the provided inaccurate price information for use in Intercontinental Exchange, an electronic electricity indexes compiled and published by trade trading platform owned by a group of electricity publications. AEP, subsequently, instituted trading companies, including us, on September measures that require all price information for use 21, 2001, the day on which all brokerage in market indexes be verified and reported commissions for trades on that exchange were through AEP s chief risk officers organization. donated to charities for the victims of the AEP has and will continue to provide to the September 11, 2001 terrorist attacks, which do FERC, the SEC and the CFTC information not meet the FERC criteria for a "wash sale but relating to price data given to energy industry do have certain characteristics in common with publications. such sales. In response to a request from the California attomey general for a copy of AEP s FERC Proposed Standard Market Design responses to the FERC inquires, we provided the Affecting AEP System pertinent information. In July 2002, the FERC issued its Standard The PUCT also issued similar data requests to Market Design (SMD) notice of proposed AEP and other power marketers. AEP responded rulemaking, one of the most sweeping rulemaking to such data request by the July 2, 2002 response proposals in its history. The proposed SMD rule date. The U.S. Commodity Futures Trading seeks to standardize the structure and operation Commission (CFTC) issued a subpoena to us on of wholesale electricity markets across the June 17, 2002 requesting information with respect country. Key elements of FERC s proposal to "wash sale trading practices. AEP responded include standard rules and processes for all users to CFTC. In addition, the U.S. Department of of the electricity transmission grid, new Justice made a civil investigation demand to AEP transmission rules and policies, and the creation and other electric generating companies of certain markets to be operated by independent concerning their investigation of the administrators of the grid in all regions. The Intercontinental Exchange. AEP has completed a FERC recently indicated that it would issue a review of our trading activities in the United States white paper on the proposal in April 2003, in for the last three years involving sequential trades response to the numerous comments FERC with the same terms and counterparties. The received on its proposal. The FERC is expected revenue from such trading is not material to our to issue its final rule in mid to late 2003. Because financial statements. AEP believes that the rule is not yet finalized, management cannot substantially all these transactions involve predict the effect of the final rule on cash flows economic substance and risk transference and do and results of operations. not constitute "wash sales . FERC ProposedSecurity Standards Affecting In August 2002, AEP received an informal data AEP System request from the SEC asking us to voluntarily provide documents related to "round trip or The FERC published for comment its proposed
'wash trades. AEP has provided the requested security standards as part of the SMD. These information to the SEC. standards are intended to ensure all market participants have a basic security program that In September 2002, AEP received a subpoena effectively protects the electric grid and related from FERC requesting information about our market activities. They require compliance by natural gas transactions and their potential impact January 1, 2004. The impact of these proposed on gas commodity prices in the New York City standards is far-reaching and includes significant area. AEP responded to the subpoena in October penalties for non-compliance. These standards L-45
apply to market operations and transmission 57, and 107 and a rescission of FIN 34. The owners. For the AEP System this includes: initial recognition and initial measurement power generation plants, transmission systems, provisions of FIN 45 is effective on a prospective distribution systems and related areas of basis to guarantees issued or modified after business. FERC is considering new proposals to December 31, 2002. The disclosure modify the scope and timetable for compliance requirements of FIN 45 are effective for financial with the standards. Unless FERC changes the statements of interim or annual periods ending scope and timing of the original proposed after December 15, 2002. standards, those standards could result in significant expenditures and operational changes There are no liabilities recorded for all of the in a compressed time frame, and may adversely guarantees described below in accordance with affect results of operations and cash flows if such FIN 45 as these guarantees were entered into costs are not recovered from customers. prior to December 31, 2002. There is no collateral held in relation to these guarantees and there is FERC Market Power Mitigation Affecting AEP no recourse to third parties in the event these System guarantees are drawn. A FERC order issued in November 2001 on Certain AEP subsidiaries have entered into AEP s triennial market based wholesale power standby letters of credit (LOC) with third parties. rate authorization update required certain These LOCs cover gas and electricity trading mitigation actions that AEP would need to take for contracts, construction contracts, insurance sales/purchases within its control area and programs, security deposits, debt service required AEP to post information on its website reserves, drilling funds and credit enhancements regarding its power system s status. As a result for issued bonds. All of these LOCs were issued of a request for rehearing filed by AEP and other at a subsidiary level of AEP in the subsidiaries market participants, FERC issued an order ordinary course of business. TCC issued one of delaying the effective date of the mitigation plan the LOCs for credit enhancement of issued until after a planned technical conference on bonds. The maximum future payments of all the market power determination. No such conference LOCs are approximately $166 million with has been held and management is unable to maturities ranging from January 2003 to predict the timing of any further action by the December 2007. TCC s LOC was for $40.9 FERC or its affect on future results of operations million with a maturity date of November 2003. and cash flows. Since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiary as collateral. Other AEP and its subsidiaries are involved in a There is no recourse to third parties in the event number of other legal proceedings and claims. these letters of credit are drawn. While management is unable to predict the ultimate outcome of these matters, it is not The following AEP subsidiaries have entered into expected that their resolution will have a material guarantees of third parties obligations: adverse effect on results of operations, cash flows or financial condition. CSW Energy and CSW International have guaranteed 50% of the required debt service
- 10. Guarantees: reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The In November 2002, the FASB issued FASB guarantee was provided in lieu of Sweeny funding Interpretation No. 45, 'Guarantors Accounting the debt reserve as a part of financing. In the and Disclosure Requirements for Guarantees, event that Sweeny does not make the required Including Indirect Guarantees of Indebtedness of debt payments, CSW Energy and CSW Others (FIN 45) which clarifies the accounting to International have a maximum future payment recognize a liability related to issuing a guarantee, exposure of approximately $3.7 million, which as well as additional disclosures of guarantees. expires June 2020.
This new guidance is an interpretation of SFAS 5, L-46
Additionally, CSW guaranteed 50% of the subsidiary of AEP sold to Centrica on December required debt service reserve for Polk Power 23, 2002) and Mutual Energy WTU L.P. (former Partners, another IPP of which CSW Energy subsidiary of AEP sold to Centrica on December owns 50%. In the event that Polk Power does not 23, 2002). At the time of sale these guarantees make the required debt payments, CSW has a were not revoked. The total future maximum maximum future payment exposure of payment exposure for both companies is approximately $4.7 million, which expires July approximately $0.6 million. In January 2003 2010. these guarantees matured and no payments under the guarantees were required. Inconnection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power See Note 26 'Minority Interest in Finance Plant, SWEPCo has agreed under certain Subsidiary for disclosure for the guaranteed conditions, to assume the revolving credit support of AEP for Caddis Partners, LLC. agreement, capital lease obligations, and term loan payments of the mining contractor. In the AEP and all its registrant and non-registrant event the mining contractor defaults under any of subsidiaries enter into several types of contracts, these agreements, SWEPCo s total future which would require indemnifications. Typically maximum payment exposure is approximately these contracts include, but are not limited to, $74 million with maturity dates ranging from April sale agreements, lease agreements, purchase 2003 to February 2012. agreements and financing agreements. Generally these agreements may include, but are not limited As part of the process to receive a renewal of a to, indemnifications around certain tax, Texas Railroad Commission permit for lignite contractual and environmental matters. At this mining, SWEPCo has agreed to provide time AEP cannot estimate the maximum potential guarantees of mine reclamation in the amount of payment for any of these indemnifications due to approximately $85 million. Since SWEPCo uses the uncertainty of future events. Inaddition, as of self-bonding, the guarantee provides for December 31, 2002, there are no liabilities SWEPCo to commit to use its resources to required for any indemnifications. complete the reclamation in the event the work is not completed by a third party miner. At AEP and its regulated and non-regulated December 31, 2002 the cost to reclaim the mine subsidiaries lease certain equipment under a isestimated to be approximately $36 million. This master operating lease. Under the lease guarantee ends upon depletion of reserves agreement, the lessor is guaranteed to receive up estimated at 2035 plus 6 years to complete to 87% of the unamortized balance of the reclamation. equipment at the end of the lease term. If the fair market value of the leased equipment is below In connection with the ability for Mutual Energy the unamortized balance at the end of the lease CPL L.P. (former subsidiary of AEP sold to term, we have committed to pay the difference Centrica on December 23, 2002) to compete in between the fair market value and the the CPL territory and to secure transition charges, unamortized balance, with the total guarantee not AEP provided a guarantee that AEP would pay to exceed 87% of the unamortized balance. At transition charges if Mutual Energy CPL failed to December 31, 2002, the maximum potential loss meet certain obligations. At the time of sale this for these lease agreements was approximately guarantee (matures in February 2003) was not $50 million assuming the fair market value of the revoked. The future maximum payment exposure equipment is zero at the end of the lease term. is $12.2 million. In February2003, the guarantee The maximum potential loss by registrant is as matured and no payments under the guarantee follows: were required. In connection with the ERCOT transmission congestion auction, AEP has guaranteed the obligations of Mutual Energy CPL L.P. (former L-47
Registrant Maximum Potential Loss Total (inmillions) Total Termination APCo Total Expense Benefits
$ 0.7 CSPCo 0.8 Number Recorded Accrued at I&M 2.0 of in 2002 12/31/02 KPCo Termi nated tin (in OPCo 0.7 Employees millions) millions)
PSO 3.3 AEGCo S 0.3 $ 0.3 SWEPCo 3.4 APCo 93 13.1 12.2 TCC 6.7 CSPCo 19 5.0 4.5 TNC 2.5 I&M 146 15.0 13.1 Other AEP non-registrant KPCo 16 2.6 2.5 Subsidiaries 29.9 OPCo 33 7.5 7.1 PSo 17 3.1 3.0 Total $50.0 SWEPCo 8 3.3 3.1 TCC 37 6.0 5.5
- 11. Sustained Earnings Improvement Initiative: TNC 20 2.0 1.6 other AEP subsidiar In response to difficult conditions in AEP s business, a Sustained Earnings Improvement -ies 731 17.5 13.0 Totals $75.A 565-9 (SEI) initiative was undertaken company-wide in L1ZQ the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings Approximately $48 million of severance expense growth. associated with 701 AEP Service Corporation employees (included in the 731 figure above) was Termination benefits expense relating to 1,120 allocated among all AEP subsidiaries. AEGCo terminated employees totaling $75.4 million pre- has no employees but receives allocated tax was recorded in the fourth quarter of 2002. Of expenses.
this amount, AEP paid $9.5 million to these terminated employees in the fourth quarter of In addition, certain buildings and corporate aircraft 2002. The termination benefits expense was are being sold in an effort to reduce ongoing classified as Maintenance and Other Operation operating expenses. expense on AEP s Consolidated Statements of Operations and as Other Operation expense on 12. Acquisitions, Dispositions and the other registrants statements of operations. Discontinued Operations: We determined that the termination of the employees under our SEI initiative did not Acquisitions constitute a curtailment under the provisions of SFAS No. 88 'Employers Accounting for SFAS 141 "Business Combinations applies to all Settlements and Curtailments of Defined Benefit business combinations initiated and Pension Plans and for Termination Benefits . consummated after June 30, 2001. The following table shows the staff reductions, 2002 termination benefits expense and the remaining termination benefits expense accrual as of Acquisition of Nordic Trading December 31, 2002: In January 2002 AEP acquired for $2.2 million and other assumed liabilities the trading operations, including key staff, of Enron's Norway and Sweden-based energy trading businesses (Nordic Trading). Results of operations are included in AEP's Consolidated Statements of Operations from the date of acquisition. The L-48
excess of cost over fair value of the net assets SWEPCo, an AEP subsidiary, purchased acquired was approximately $4.0 million which the Dolet Hills mining operations and was recorded as Goodwill. Subsequently in the assumed the existing mine reclamation fourth quarter of 2002, a decision was made to liabilities at its jointly owned lignite exit the non-core trading business in Europe and reserves in Louisiana. to close or sell Nordic Trading as discussed under Quaker Coal Company as part of a the "Discontinued Operations section of this note. bankruptcy proceeding settlement. AEP also assumed additional liabilities of Acquisition of USTI approximately $58 million. The acquisition InJanuary 2002, AEP acquired 100% of the stock includes property, coal reserves, mining of United Sciences Testing, Inc. (USTI) for $12.5 operations and royalty interests in million. USTI provides equipment and services Colorado, Kentucky, Ohio, Pennsylvania related to automated emission monitoring of and West Virginia. AEP continues to combustion gases to both AEP affiliates and operate the mines and facilities which external customers. Results of operations are employ over 800 individuals. See Note included in AEP's Consolidated Statements of 13b "Asset Impairments and Investment Operations from the date of acquisition. Value Losses . MEMCO Barge Line added 1,200 hopper 2001 barges and 30 towboats to AEP s existing barging fleet. MEMCO s 450 employees On June 1, 2001, AEP, through a wholly owned operate the barge line. MEMCO added subsidiary, purchased Houston Pipe Line major barging operations on the Company and Lodisco LLC for $727 million from Mississippi and Ohio rivers to AEP s Enron. The acquired assets include 4,200 miles barging operations on the Ohio and of gas pipeline, a 30-year $274 million prepaid Kanawha rivers. lease of a gas storage facility and certain gas
- U.K. Generation added 4,000 megawatts marketing contracts. The purchase method of of coal-fired generation from Fiddlers accounting was used to record the acquisition. Ferry, a four-unit, 2,000-megawatt station According to APB Opinion No. 16 'Business on the River Mersey in northwest England, Combinations AEP recorded the assets acquired approximately 200 miles from London and and liabilities assumed at their estimated fair Ferrybridge, a four-unit, 2,000-megawatt values determined by independent appraisal or by station on the River Aire in northeast Companys management based on information England, approximately 200 miles from currently available and on current assumptions as London and related coal stocks. See to future operations. Based on a final purchase Note 13b "Asset Impairments and price allocation the excess of cost over fair value Investment Value Losses .
of the net assets acquired was approximately
- A 20% equity interest in Caiua, a Brazilian
$153 million and is recorded as Goodwill. SFAS electric operating company which is a 142 "Goodwill and Other Intangible Assets treats subsidiary of Vale. See Note 21, "Power goodwill as a non-amortized, non-wasting asset and Distribution Projects . AEP converted effective January 1, 2002. Therefore, Goodwill a total of $66 million on an existing loan was amortized for only seven months in 2001 on and accrued interest on that loan into a straight-line basis over 30 years. The purchase Caiua equity. See Note 13b "Asset method results in the assets, liabilities and Impairments and Investment Value earnings of the acquired operations being Losses. included in AEP s consolidated financial Indian Mesa Wind Project consisting of statements from the purchase date. 160 megawatts of wind generation located near Fort Stockton, Texas. AEP also purchased the following assets or Acquired existing contracts and hired key acquired the following businesses from July 1, staff from Enron s London-based 2001 through December 31, 2001 for an international coal trading group. aggregate total of $1,651 million: L-49
Regarding the 2002 and 2001 acquisitions, SEEBOARD s assets and liabilities of management has recorded the assets acquired discontinued operations were: and liabilities assumed at their estimated fair values in accordance with APB Opinion No. 16 December 31, and SFAS 141 as appropriate based on currently 2001 available information and on current assumptions (in millions) as to future operations. Assets: Current Assets S 324 Plant,Property Dispositions and Equipment, Net 1,283 Goodwill 1,129 2002 other Assets 96 Total Assets of Di scontinued In 2002, AEP completed a number of disposals of Operations assets determined to be non-core: Liabilities: Current Liabilities S 752 Disposal of SEEBOARD Long-term Debt 701 Deferred Income On June 18, 2002, AEP, through a wholly owned Taxes 268 subsidiary, entered into an agreement, subject to other Liabilities 77 European Union (EU) approval, to sell its Total Liabilities of Discontinued consolidated subsidiary SEEBOARD, a U.K. operations electricity supply and distribution company. EU approval was received July 25,2002 and the sale was completed on July 29, 2002. AEP received Disposal of CitiPower approximately $941 million in net cash from the On July 19, 2002, AEP, through a wholly owned sale, subject to a working capital true up, and the subsidiary entered into an agreement to sell buyer assumed SEEBOARD debt of CitiPower, a retail electricity and gas supply and approximately $1.12 billion, resulting in a net loss distribution subsidiary in Australia. AEP of $345 million at June 30, 2002. In accordance completed the sale on August 30, 2002 and with SFAS 144 the results of operations of received net cash of approximately $175 million SEEBOARD have been classified as and the buyer assumed CitiPower debt of Discontinued Operations for all years presented. approximately $674 million. AEP recorded a net A net loss of $22 million was classified as charge totaling $125 million as of June 30, 2002. Discontinued Operations in the second quarter of The charge included an impairment loss of $98 2002. The remaining $323 million of the net loss million on the remaining carrying value of an has been classified as a transitional impairment intangible asset related to a distribution license for loss from the adoption of SFAS 142 (see Notes 2 CitiPower. The remaining $27 million of net loss and 3) and has been reported as a Cumulative was classified as a transitional goodwill Effect of Accounting Change retroactive to impairment loss from the adoption of SFAS 142 January 1, 2002. A $59 million reduction of the (see Notes 2 and 3) and was recorded as a net loss was recognized in the second half of Cumulative Effect of Accounting Change 2002 to reflect changes in exchange rates to retroactive to January 1, 2002. closing, settlement of working capital true-up and selling expenses. The net total loss recognized on The loss on the sale of CitiPower increased $24 the disposal of SEEBOARD was $286 million. million to $149 million in the second half of 2002 Proceeds from the sale of SEEBOARD were used based on actual closing amounts and exchange to pay down bank facilities and short-term debt. rates. The assets and liabilities of SEEBOARD were CitiPowers results of operations have been aggregated on AEP s Consolidated Balance reclassified as Discontinued Operations in Sheets as Assets of Discontinued Operations and accordance with SFAS 144. The assets and Liabilities of Discontinued Operations as of liabilities of CitiPower have been aggregated on December 31, 2001. The major classes of the December 31, 2001, AEP balance sheet as L-50
Assets of Discontinued Operations and Liabilities of Discontinued Operations. The major classes of CitiPower CitiPower s assets and liabilities of discontinued (in millions) operations are: Revenues: December 31, 12 months ended 2001 12/31/02 $ 204 (in millions) 12 months ended Assets: 12/31/01 Current Assets $ 138 350 Plant, Property and 12 months ended Equipment, Net 495 12/31/00 338 Goodwill/Intangibles 466 other Assets 23 Pretax Profit (Loss): Total Assets of Discontinued operations 12 months ended 12/31/02 $ (190) 12 months ended Liabilities: 12/31/01 (4) current Liabilities $ 83 12 months ended Long-term Debt 612 12/31/00 20 Deferred Income Taxes 55 other Liabilities 34 Total Liabilities of Dispositionof Texas REPs Discontinued In April 2002, AEP reached a definitive operations $L84 agreement, subject to regulatory approval, to sell two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other Total revenues and pretax profit (loss) of the consumer services. PUCT regulatory approval for discontinued operations of SEEBOARD and the sale was obtained in December 2002. On CitiPower were: December 23, 2002 AEP sold to Centrica, the general partner interests and the limited partner SEEBOARD interests in Mutual Energy CPL L.P. and Mutual (in millions) Energy WTU L.P. for a base purchase price paid Revenues: in cash at closing and certain additional payments, including a net working capital 12 months ended payment. Centrica paid a base purchase price of 12/31/02 $ 694 $145.5 million which was based on a fair market 12 months ended value per customer established by an 12/31/01 1,451 independent appraiser and an agreed customer 12 months ended count. AEP recorded a net gain totaling $83.7 12/31/00 1,596 million in Other Income. AEP (through TCC and TNC) will provide Centrica with a power supply Pretax Profit: contract for the two REPs and back-office services related to these customers for a two-year 12 months ended period. In addition, AEP retained the right to 12/31/02 $ 180 share in earnings from the two REPs above a 12 months ended threshold amount through 2006 in the event the 12/31/01 104 Texas retail market develops increased earnings 12 months ended opportunities. Under the Texas Legislation, REPs 12/31/00 91 are subject to a clawback liability if customer change does not attain thresholds required bythe legislation. AEP is responsible for a portion of such liability, if any, for the period it operated the REPs in the Texas competitive retail market (January 1,2002 through December 23,2002). In addition, AEP retained responsibility for regulatory L-51
obligations arising out of operations before quarter of 2001. The writedown is included in closing. AEP s wholly-owned subsidiary Mutual Other Income on AEP s Consolidated Statements Energy Service Company LLC (MESC) received of Operations. On February 26, 2001 an an up-front payment of approximately $30 million agreement to sell the Company s 50% interest in from Centrica associated with the back-office Yorkshire was signed. On April 2,2001, following service agreement, and MESC deferred its right the approval of the buyer s shareholders, the sale to receive payment of an additional amount of was completed without further impact on AEP s approximately $9 million to secure certain consolidated earnings. contingent obligations. These prepaid service revenues were deferred on the books of MESC to In December 2000, CSW International, a be amortized over the two-year term of the back subsidiary company sold its investment in a office service agreement. Chilean electric company for $67 million. A net loss on the sale of $13 million ($9 million after tax) 2001 is included in Other Income, and includes $26 million ($17 million net of tax) of losses from In March 2001, CSWE, a subsidiary company, foreign exchange rate changes that were completed the sale of Frontera, a generating plant previously reflected in Accumulated Other that the FERC required to be divested in Comprehensive Income. Inthe second quarter of connection with the merger of AEP and CSW. 2000 AEP management determined that the then The sale proceeds were $265 million and resulted existing decline in market value of the shares was in an after tax gain of $46 million. other than temporary. As a result the investment was written down by $33 million ($21 million after In July 2001, AEP, through a wholly owned tax) in June 2000. The total loss from both the subsidiary, sold its 50% interest in a 120- write down of the Chilean investment to market in megawatt generating plant located in Mexico. the second quarter and from the sale in the fourth The sale resulted in an after tax gain of quarter was $46 million ($30 million net of tax). approximately$11 million. - In July 2001, OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale is expected to have a nominal impact on the results of operations and cash flows of OPCo and AEP. In December 2001, AEP completed the sale of its ownership interests in the Virginia and West Virginia PCS (personal communications services) Alliances for stock, resulting in an after tax gain of approximately $7 million. During 2002, due to decreasing market value of the shares, AEP reduced the value of them to zero. 2000 In December 2000, AEP, through a wholly owned subsidiary, committed to negotiate a sale of its 50% investment in Yorkshire, a U.K. electricity supply and distribution company. As a result a
$43 million writedown ($30 million after tax) was recorded in the fourth quarter of 2000 to reflect the net loss from the expected sale in the first L-52
Discontinued Operations The operations shown below, affecting AEP, were discontinued or classified as held for sale in 2002. Results of operations of these businesses have been reclassified as shown in the following table: SEE-BOARD CitiPower Pushan Eastex Total (in millions) 2002 Revenue $ 694 $204 $57 $ 73 $1,028 2001 Revenue 1,451 350 57 - 1,858 2000 Revenue 1,596 338 57 - 1,991 2002 Earnings (Loss) After Tax 96 (123) (7) (156) (190) 2001 Earnings (Loss) After Tax 88 (6) 4 86 2000 Earnings (Loss) After Tax 99 17 7 (1) 122
- 13. Asset Impairments and Investment Value Losses:
In 2002 AEP recorded pre-tax impairments of assets (including goodwill) and investments totaling $1.426 billion (consisting of approximately $866.6 million related to Asset Impairments, $321.1 million related to Investment Value and Other Impairment Losses, and $238.7 million related to Discontinued Operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and otherfactors. These impairments excludethetransitional impairmentlossfrom adoption of SFAS142 (see Notes 2 and 3). The categories of impairments included: 2002 Pre-Tax Estimated Loss (in millions) Asset Impairments Held for Sale $ 483.1 Asset Impairments Held and Used 651.4 Investment Value Losses 291.9 Total $ 1.426.4 L-53
- a. Assets Held for Sale In 2002, AEP (and its registrant subsidiaries, as applicable) recorded the following estimated loss on disposal of assets (including Goodwill) held for sale:
2002 Pre-Tax Assets Estimated Loss Held for Sale on Disposal Business Registrant (in millions) Eastex $218.7 Wholesale AEP Pushan Power 20.0 Other AEP Total Impairment Losses Included in Discontinued Operations $238.7 Telecommunication AEPC/C3 $158.5 Other AEP. Newgulf Facility 11.8 Wholesale AEP Nordic Trading 5.3 Wholesale AEP Excess Equipment 23.9 Wholesale AEP Excess Real Estate 15.7 Wholesale AEP Total Included in Asset Impairment Losses $215.2 Telecommunications AFN $ 13.8 Other AEP Water Heater AEP, APCo, CSPCo, Program 3.2 Wholesale I&M, KPCo and OPCo Gas Power Systems 12.2 Wholesale AEP Total Included in Investment Value and Other Impairment Losses Total-All Held for Sale Losses $483.1 Eastex In 1998, CSW began construction of a natural gas-fired cogeneration facility (Eastex) located near Longview, Texas and commercial operations commenced in December 2001. In June 2002, AEP requested that the FERC allow it to modify the FERC Merger Order and substitute Eastex as a required divestiture under the order, due to the fact that the agreed upon market-power related divestiture of a plant in Oklahoma was no longer feasible. The FERC approved the request at the end of September 2002. Subsequently, in the fourth quarter of 2002 AEP solicited bids for the sale of Eastex and several interested buyers were identified by December 2002. A sale of assets is expected to be completed bythe end of 2003 with an estimated pre-tax loss on sale of $218.7 million included in Discontinued Operations in AEP s Consolidated Statements of Operations. The estimated loss was based on the estimated fair value of the facility and indicative bids by interested buyers. L-54
Results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144 as shown in Note 12. The assets and liabilities of Eastex have been included on AEP s Consolidated Balance Sheets as held for sale. The major classes of assets and liabilities held for sale are: 2002 2001 (in millions) Assets: Current Assets $15 $ - Property, Plant and Equipment, Net - 217 Other Assets - 3 Total Assets Held for Sale _ 22Q Liabilities: Current Liabilities $ 8 $ 5 Other Liabilities 4 1 Total Liabilities Held for Sale $1 $_6 Pushan Power Plant In the fourth quarter of 2002, AEP began active negotiations to sell its interest in the Pushan Power Plant (Pushan) in Nanyang, China to the minority interest partner. Negotiations are expected to be completed by the second quarter of 2003 with an estimated pre-tax loss on disposal of $20.0 million, based on an indicative price expression. The estimated pre-tax loss on disposal is classified in Discontinued Operations in AEP s Consolidated Statements of Operations. Results of operations of Pushan have been reclassified as Discontinued Operations in accordance with SFAS 144 as discussed in Note 12. The assets and liabilities of Pushan have been classified on AEP s Consolidated Balance Sheets as held for sale. The major classes of assets and liabilities held for sale are: 2002 2001 (in millions) Assets: Current Assets $ 19 $ 17 Property, Plant and Equipment, Net 132 161 Total Assets Held for Sale $151 $178 Liabilities: Current Liabilities $ 28 $ 27 Long-term Debt 25 30 Other Liabilities 26 24 Total Liabilities Held for Sale £19 $_81 Telecommunications AEP had developed businesses to provide telecommunication services to businesses and to other telecommunication companies through broadband fiber optic networks operated in conjunction with AEP s electric transmission and distribution lines. The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the difficult economic conditions in these businesses and the overall telecommunications industry, and other operating problems, the AEP Board approved in December 2002 a plan to cease operations of these businesses. AEP took steps to market the assets of the businesses to potential interested buyers in the fourth quarter of 2002. A number of potential buyers have made offers for the assets of C3. Potential L-55
buyers have indicated interest in the assets of AFN. A formal offering of the assets of AEPC will begin early in 2003. The complete sale of all telecommunication assets isexpected to be completed bythe end of 2003 with an estimated pre-tax impairment loss of $158.5 million (related to AEPC and C3) classified in Asset Impairments in AEP s Consolidated Statements of Operations and an estimated pre-tax loss in value of the investment in AFN of $13.8 million classified in Investment Value and Other Impairment Losses in AEP s Consolidated Statements of Operations. The estimated losses are based on indicative bids by potential buyers. $6 million and $182 million of Property, Plant and Equipment, net of accumulated depreciation of the telecommunication businesses have been classified on AEP s Consolidated Balance Sheets as held for sale in 2002 and 2001, respectively. Newgulf Facility In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility located near Newgulf, Texas (Newgulf). In October 2002 AEP began negotiations with a likely buyer of the facility. A sale is now expected to be completed by the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on an indicative bid by the likely buyer. The estimated loss on disposal is classified in Asset Impairments on AEP s Consolidated Statements of Operations. Newgulf s Property, Plant and Equipment, net of accumulated depreciation, of $6 million in 2002 and $17 million in 2001 has been classified on AEP s Consolidated Balance Sheets as held for sale. Nordic Trading In October 2002 AEP announced that its ongoing energy trading operations would be centered around its generation assets. As a result, AEP took steps to exit its coal, gas, and electricity trading activities in Europe, except for those activities necessary to support the U.K. Generation operations. The Nordic Trading business acquired earlier in 2002 (see Note 12) was made available for sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3 million, consisted of impairment of goodwill of $4.0 million (see Note 3) and impairment of assets of $1.3 million. The estimated loss of $5.3 million is included in Asset Impairments on AEP s Consolidated Statements of Operations. Management s determination of a zero fair value was based on discussions with a potential buyer. There are no assets and liabilities of Nordic Trading to be classified on AEP s Consolidated Balance Sheets as held for sale. Excess Equipment In November 2002, as a result of a cancelled development project, AEP obtained title to a surplus gas turbine generator. AEP has been unsuccessful in finding potential buyers of the unit, including its own internal generation operators, due to an over-supply of generation equipmentavailableforsale. Sale of the turbine is now projected before the end of 2003 with an estimated 2002 pre-tax loss on disposal of $23.9 million, based on market prices of similar equipment. The loss is included in Asset Impairments on AEP s Consolidated Statements of Operations. The Other asset of $12 million in 2002 and $31 million in 2001 has been classified on AEP s Consolidated Balance Sheets as held for sale. Excess Real Estate Inthe fourth quarter of 2002, AEP began to market an under-utilized office building in Dallas, TX obtained through the merger with CSW. One prospective buyer has executed an option to purchase the building. Sale of the facility is projected by second quarter 2003 and an estimated 2002 pre-tax loss on disposal of $15.7 million has been recorded, based on the option sale price. The estimated loss is included in Asset Impairments on AEP s Consolidated Statements of Operations. The Property asset of $18 million in 2002 and $36 million in 2001 has been classified on AEP s Consolidated Balance Sheets as held for sale. L-56
Water Heater Program AEP, APCo, CSPCo, I&M, KPCo and OPCo operated a program to lease electric water heaters to residential and commercial customers until a decision was reached in the fourth quarter of 2002 to discontinue the program and to offer the assets for sale. Negotiations are underway with a qualified buyer, and sale of the assets is projected by the end of the first quarter of 2003. AEP s estimated 2002 pre-tax loss on disposal of $3.20 million ($50 thousand for APCo, $615 thousand for CSPCo, $643 thousand for l&M, $11 thousand for KPCo, $1.757 million for OPCo and $126 thousand for other AEP non-registrant subsidiaries) was based on the expected contract sales price. The loss isincluded in InvestmentValue and Other Impairment Losses on AEP s Consolidated Statements of Operations and in Nonoperating Expenses on the statements of income of the registrant subsidiaries. The assets and liabilities have been classified on AEP s Consolidated Balance Sheets as held for sale. The major classes of assets held for sale are: 2002 2001 (in millions) Assets: Current Assets $ 1 $ 2 Property, Plant and Equipment, Net 38 48 Total Assets Held for Sale $3X _ Gas Power Systems AEP acquired in 2001 a 75% interest in a startup company seeking to develop low-cost peaking generator sets powered by surplus jet turbine engines. The first quarter of 2002, AEP recognized a goodwill impairment loss of $12.2 million due to technological and operating problems (See Note 3). The loss was recorded in Investment Value and Other Impairment Losses on AEP s Consolidated Statements of Operations. The fair values of the remaining assets and liabilities were excluded from AEP s Consolidated Balance Sheets as held for sale, as the impact was insignificant. AEP s remaining interest was sold in January 2003.
- b. Assets Held and Used In 2002, AEP recorded the following impairments related to assets (including Goodwill) held and used to Asset Impairments on AEP s Consolidated Statements of Operations:
Assets Business Held and Used 2002 Pre-Tax Loss Segment Registrant (in millions) U.K. Generation $548.7 Wholesale AEP AEP Coal 59.9 Wholesale AEP Texas Plants 38.1 Wholesale AEP and TNC Ft. Davis Wind Farm 4.7 Wholesale AEP and TNC Total ALL Held and Used Losses $651.4 U.K. Generation Plants In December 2001, AEP acquired two coal-fired generation plants (U.K. Generation) in the U.K. for a cash payment of $942.3 million and assumption of certain liabilities. Subsequently and continuing through 2002, wholesale U.K. electric power prices declined sharply as a result of domestic over-capacity and static demand. External industry forecasts and AEP s own projections made during the fourth quarter of 2002 L-57
indicate that this situation may extend many years into the future. As a result, the U.K. Generation fixed asset carrying value at year-end 2002 was substantially impaired. A December2002 probability-weighted discounted cash flow analysis of the fair value of our U.K. Generation indicated a 2002 pre-tax impairment loss of $548.7 million, including a goodwill impairment of $166.1 million as discussed in Note 3. The cash flow analysis used a discount rate of 6% over the remaining life of the assets and reflected assumptions for future electricity prices and plant operating costs. This impairment loss is included inAsset Impairments on AEP s Consolidated Statements of Operations. AEP Coal In October2001, AEP acquired out of bankruptcy certain assets and assumed certain liabilities of nineteen coal mine companies formerly known as 'Quaker Coal and re-identified as "AEP Coal . During 2002 the coal operations suffered a decline in forward prices and adverse mining factors that culminated in the fourth quarter of 2002 and significantly reduced mine productivity and revenue. Based on an extensive review of economically accessible reserves and other factors, future mine productivity and production is expected to continue to be below historical levels. In December 2002, a probability-weighted discounted cash flow analysis of fair value of the mines was performed which indicated a2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of $3.6 million as discussed in Note 3. This impairment loss is included in Asset Impairments on AEP s Consolidated Statements of Operations. Texas Plants In September 2002, AEP proposed closing 16 gas-fired power plants in the ERCOT control area of Texas (8 TNC plants and 8 TCC plants). ERCOT indicated that it may designate some of those plants as ureliability must run (RMR) status. In October ERCOT designated seven RMR plants (3 TNC plants and 4 TCC plants) and approved AEP s plan to inactivate nine other plants (5 TNC plants and 4 TCC plants). The process of moving the plants to inactive status took approximately two months. Employees of the plants moved to inactive status (approximately 180) were eligible for severance and outplacement services. As a result of the decision to inactivate TNC plants, a write-down of utility assets of approximately $34.2 million (pre-tax) was recorded in Asset Impairments expense during the third quarter 2002 on AEP s and TNC s Statements of Operations. The decision to inactivate the TCC plants resulted in a write-down of utility assets of approximately $95.6 million (pre-tax), which was deferred and recorded in Regulatory Assets during the third quarter 2002 in AEP s Consolidated Balance Sheets (in RegulatoryAssets Designated For or Subject to Securitization on TCC s Consolidated Balance Sheets). During the fourth quarter 2002, evaluations continued as to whether assets remaining at the inactivated plants, including materials, supplies and fuel oil inventories, could be utilized elsewhere within the AEP System. As a result of such evaluations, TNC recorded an additional asset impairment charge to Asset Impairments expense of $3.9 million (pre-tax) in the fourth quarter 2002. In addition TNC recorded related inventory write-downs of $2.6 million [$1.2 million in Fuel and Purchased Energy: Electricity on AEP (Fuel Expense on TNC) and $1.4 million in Maintenance and Other Operation expense on AEP (Other Operation on TNC)]. Similarly, TCC recorded an additional asset impairment write-down of $6.7 million (pre-tax), which was deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to Securitization on TCC s Consolidated Balance Sheets) in the fourth quarter 2002. TCC also recorded related inventory write-downs of $14.9 million which was deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to Securitization on TCC s Consolidated Balance Sheets) in the fourth quarter 2002. The total Texas plant asset impairment of $38.1 million in 2002 (all related to TNC) is included in Asset Impairments on AEP s and TNC s Consolidated Statements of Operations. RMR plants are required to ensure the reliability of the power grid, even if electricityfrom those plants isnot required to meet market needs. ERCOT and AEP negotiated interim contracts forthe seven RMR plants L-58
through December 2003, however, ERCOT has the right to terminate the plants from RMR status upon 90 days written notice. In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either inactivated or designated as RMR status. See Texas Restructuring section of the "Customer Choice and Industry Restructuring Note 8 for further discussion of the divestiture plan and anticipated timeline. Ft Davis Wind Farm In the 1990 s, CSW developed a 6 MW facility wind energy project located on a lease site near Ft. Davis, Texas. In the fourth quarter of 2002 AEP engineering staff determined that operation of the facility was no longer technically feasible and the lease of the underlying site should not be renewed. Dismantling of the facility will be complete by the end of 2003 with an estimated 2002 pre-tax loss on abandonment of $4.7 million. The loss was recorded in Asset Impairments on AEP s Consolidated Statements of Operations and TNC s Statements of Operations. The facilitywill continue to be classified as held and used until disposal is complete.
- c. Investment Values In 2002, AEP recorded the following declines in fair value on investments accounted for underAPB 18 that were considered to be other than temporarily impaired as shown in the table below:
Investment Value Impairment 2002 Pre-Tax Business Loss Items Estimated Loss Segment Registrant (in millions) Grupo Rede Investment Brazil $217.0 Other AEP South Coast Power 63.2 Other AEP Misc. Technology Investments 11.7 Other AEP Total $291.9 Grupo Rede Investment In December 2002, AEP recorded an other than temporary impairment totaling $141.0 million ($217.0 million net of federal income tax benefit of $76.0 million) of its 44% equity investment in Vale and its 20% equity interest in Caiua, both Brazilian electric operating companies (referred to as Grupo Rede). This amount is included in Investment Value and Other Impairment Losses on AEP s Consolidated Statements of Operations. As of September 30,2002, AEP had not recognized its cumulative equity share of operating and foreign currency translation losses of approximately $88 million and $105 million, respectively, due to the existence of a put option that permits AEP to require Grupo Rede to purchase our equity at a minimum price equal to the U.S. dollar equivalent of the original purchase price. In January 2002 AEP evaluated through an independent credit assessment the ability of Grupo Rede to fulfill its responsibilities under the put option and concluded that the carrying value of the original investment was reasonable. During 2002, there has been a continuing decline in the Brazilian power industry and the value of the local currency. Events in the fourth quarter of 2002 led us to change our view that Grupo Rede would be able to fulfill its responsibilities under the put option. These events included two downgrades of Caiua debt by Moody s, resulting in a rating of Caal. Caiua is an intermediate holding company which owns substantially all of the utility companies in the Grupo Rede system. The downgrading of Caiua s credit ratings to a level well below investment grade casts significant doubt on the ability of Grupo Rede to honor the put option. L-59
Grupo Rede is in the process of restructuring some of its debts, and as a condition for participating in the restructuring, during November2002 a creditor of Grupo Rede requested thatAEP agree not to exercise the put option prior to March 31, 2007. AEP agreed and in exchange received an extension of the put option from the previous end date of 2009 through 2019. Based on the factors noted above, AEP could no longer reasonably believe that our investment could be recovered, resulting in the recording of the impairment. South Coast Power Investment South Coast Power is a 50% owned joint venture that was formed in 1996 to build and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K.. South Coast Power is subject to the same adverse wholesale electric power rates described for U.K. Generation above. A December2002 projected cash flow estimate of the fair value of the investment indicated a 2002 pre-tax other than temporary impairment of the equity interest (which included the fairvalue of supply contracts held by South Coast Power and accounted for in accordance with SFAS 133) in the amount of $63.2 million. This loss of investment value is included in Investment Value and Other Impairment Losses on AEP s Consolidated Statements of Operations. Technology Investments AEP previously made investments totaling $11.7 million in four early-stage or startup technologies involving pollution control and procurement. An analysis in December 2002 of the viability of the underlying technologies and the projected performance of the investee companies indicated that the investments were unlikely to be recovered, and an otherthan temporary impairment of the entire amount of the equity interest under APB 18 was recorded. The loss of investment value is included in Investment Value and Other Impairment Losses on AEP s Consolidated Statements of Operations.
- 14. Benefit Plans:
Pension and Other Postretirement Benefits In the U.S. AEP sponsors two qualified pension plans and two nonqualified pension plans. Substantially all employees in the U.S. are covered by either one qualified plan or both a qualified and a nonqualified pension plan. Other postretirement benefit (OPEB) plans are sponsored by the AEP System to provide medical and death benefits for retired employees in the U.S. AEP also has a foreign pension plan for employees of AEP Energy Services U.K. Generation Limited (Genco) in the U.K. Genco employees participate in their existing pension plan acquired as part of AEP s purchase of two generation plants in the U.K. in December 2001. L-60
The following tables provide a reconciliation of the changes inthe plans' benefit obligations and fairvalue of assets over the two-year period ending December 31, 2002, and a statement of the funded status as of December 31 for both years: U.S. U.S. Pension Plans OPEB Plans 2002 2001 2002 2001 7in millions) Reconciliation of Benefit Obligation: obligation at January 1 $3,292 $3,161 S 1,645 $1,668 Service Cost 72 69 34 30 Interest Cost 241 232 114 114 Participant Contributions 13 8 Plan Amendments (2) 7 (a) Actuarial (Gain) Loss 258 121 152 192 Divestitures (287) (b) Benefit Payments (278) (291) (81) (88) curtailments 1 obligation at December 31 SL5 83 S 9n SL~s SI-6A Reconciliation of Fair value of Plan Assets: Fair value of Plan Assets at January 1 $3, 438 $3,911 S 711 S 704 Actual Return on Plan Assets (371) (182) (57) (31) company contributions 6 137 118 Participant contributions 13 8 Benefit Payments (278) (291) (8) (88) Fair value of Plan Assets at December 31 ILI79 .L-M~ S 71 Funded status: Funded Status at December 31 S (788) S 146 S(1,154) S (934) unrecognized Net Transition (Asset) obligation (7) (15) 233 267 unrecognized Prior-Service Cost (13) (12) 6 7 Unrecognized Actuarial (Gain) Loss 1.02 35 896 649 Prepaid Benefit (Accrued Liability) S.212 SL154 S-- U) S (15) (a) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line. (b) Related to the sale of central Ohio coal Company, southern ohio Coal company and Windsor Coal Company. The following table provides the amounts for prepaid benefit costs and accrued benefit liability recognized in the Consolidated Balance Sheets as of December 31 of both years. The amounts for additional minimum liability, intangible asset and Accumulated Other Comprehensive Income for 2001 and 2002 were recorded in 2002. U.S. U.S. Pension Plans OPEB Plans 2002 2001 2002 2001 (in millions) Prepaid Benefit Costs S 255 S 205 S - S 1 Accrued Benefit Liability (44) (51) (19) (16) Additional Minimum Liability (944) (15) N/A N/A Intangible Asset 45 9 N/A N/A Accumulated other Comprehensive Income 900 6 N/A Net Asset (Liability) S(19) other Comprehensive (Income) Expense Attributable to change in Additional Pension Liability Recognition 2894 -NA N/A = Not Applicable L-61
The value of our qualified plans assets has decreased from $3.438 billion at December 31,2001 to $2.795 billion at December 31, 2002. The qualified plans paid $272 million in benefits to plan participants during 2002 (nonqualified plans paid $6 million in benefits). The investment returns and declining discount rates have changed the status of our qualified plans from overfunded (plan assets in excess of projected benefit obligations) by $146 million at December 31, 2001 to an underfunded position (plan assets are less than projected benefit obligations) of $788 million at December 31, 2002. Due to the qualified plans currently being underfunded, the Company recorded a charge to Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of $315 million, offset by a Minimum Pension Liability of $662 million and reduction to prepaid costs and intangible assets of $238 million. The charge to OCI does not affect earnings or cash flow. The OCI charge for each AEP subsidiary registrant is recorded in Minimum Pension Liability in the respective registrant s Consolidated Statements of Comprehensive Income. Also, because of the recent reductions in the funded status of our qualified plans, we expect to make cash contributions to our qualified plans of approximately$66 million in 2003 increasing to approximately$108 million peryearby 2005. The AEP System s qualified pension plans had accumulated benefit obligations in excess of plan assets of $661 million at December 31, 2002. The AEP System s nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $72 million at December 31, 2002 and $66 million at December 31, 2001. There are no assets in the nonqualified plans. The AEP System s OPEB plans had accumulated benefit obligations in excess of plan assets of $1,154 million and $934 million at December 31, 2002 and 2001, respectively. The Genco pension plan had $7 million and $10 million at December 31, 2002 and 2001, respectively, of accumulated benefit obligations in excess of plan assets. The following table provides the components of AEP s net periodic benefit cost (credit) for the plans for fiscal years 2002, 2001 and 2000: U.S. U.S. Pension Plans OPEB Plans 2002 2001 2000 2002 2001 2000 (in millions) Service cost S 72 $ 69 S 60 S 34 S 30 $ 29 Interest Cost 241. 232 227 114 114 106 Expected Return on Plan Assets (337) (338) (321) (62) (61) (57) Amortization of Transition (Asset) obligation (9) (8) (8) 29 30 41 Amortization of Prior-service Cost (1) - 13 - - - Amortization of Net Actuarial (Gain) Loss (10) (24) (39) 27 18 4 Net Periodic Benefit cost (Credit) (44) (69) (68) 142 131 123 curtailment Loss (a) - - - - 1 79 Net Periodic Benefit cost (credit) After Curtailments 5 44) 5142 13 )a) M292 (a) curtailment charges were recognized during 2000 for the shutdown of Central Ohio Coal company, Southern Ohio coal Company and Windsor coal company. L-62
The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant and other non-registrant subsidiaries for fiscal years 2002, 2001 and 2000: U.S. U.S Pension Plans OPEB Plans 2002 2001 2000 2002 2001 2000 (i thousands) APCo S (9,988) S(13 645) S(14,047) S 25,107 S 22,810 S 22,139 CSPCO (8, 328) (10,624) (10,905) 11,494 10,328 9,643 I&M (4,206) (7, 805) (8,565) 17,608 15,077 14,155 KPCo (1,406) (1,922) (2,075) 2,986 2,438 2,364 OPCo (11, 360) (14,879) (15,041) 22,608 34,444 116,205 PSO (3, 819) (2,480) (2,196) 8,436 6,187 4,277 SWEPCo (2,245) (3,051) (2,606) 8,371 6,399 4,152 TCC (4,786) (3,411) (2,986) 10,733 8,214 6,656 TNC (1, 104) (1,644) (1,585) 4,798 3,729 2,929 other Non-Registrant Subsidiaries 3.657 (9.,13) (7.546) 29.722 22.278 19.798 Total SW4 585 £(6BAQ- ) IM 75-5 ) S4.6 1194S0L The weighted-average assumptions as of December 31, used in the measurement of AEP s benefit obligations are shown in the following tables: U.S. U.S. Pension Plans OPEB Plans 2002 2001 2000 2002 2001 2000 6.7 5 .% % Discount Rate 6.75 7.25 7.50 6.75 7.25 7.50 Expected Return on Plan Assets 9.00 9.00 9.00 8.75 8.75 8.75 Rate of Compensation Increase 3.7 3.7 3.2 N/A N/A N/A L-63
In determining the discount rate in the calculation contributions. Beginning in 2001, AEP s of future pension obligations we review the contributions to the two largest plans increased to interest rates of long-term bonds that receive one 75 cents for every dollar of the first 6% of eligible of the two highest ratings given by a recognized employee compensation from the previous rate of rating agency. As a result of a decrease in this 50 cents. The cost for contributions to these benchmark rate during 2002, we determined that plans totaled $60.1 million in 2002, $55.6 million a decrease in our discount rate from 7.25% at in 2001 and $36.8 million in 2000. December 31, 2001 to 6.75% at December 31, 2002 was appropriate. The following table provides the cost for contributions to the savings plans by the following For OPEB measurement purposes, a 10% annual AEP registrant and other non-registrant rate of increase in the per capita cost of covered subsidiaries for fiscal years 2002,2001 and 2000: health care benefits was assumed for 2003. The rate was assumed to decrease gradually each 2002 2001 2000 (in thousands) year to a rate of 5% through 2008 and remain at APCo S 6,722 $7,031 S 3,988 that level thereafter. CSPCo 2,784 2,789 1,638 I&M 8,039 7,833 4,231 KPCo 1,043 1,016 544 Assumed health care cost trend rates have a oPCo 5,785 6,398 3,713 significant effect on the amounts reported for the PSO 2,260 2,235 2,306 SWEPCo 2,765 2,776 2,880 OPEB health care plans. A 1% change in TCC 3,054 3,046 3,161 assumed health care cost trend rates would have TNC 1,574 1,558 1,708 Other Non-the following effects: Registrant Subsidiaries 26.094 20 869 12,677 Total 1% Increase 1% Decrease (in millions) Effect on total service On January 1, 2003, the two major AEP Savings and interest cost components of net Plans merged into a single plan. periodic postretirement ealth care benefit cost S 21 $ (17) Other UMWA Benefits Effect on the health care component of the AEP and OPCo provide UMWA pension, health accumulated Dostretirement and welfare benefits for certain unionized mining benefit obligation 237 (193) employees, retirees, and their survivors who meet eligibility requirements. The benefits are AEP Savings Plans administered by UMWA trustees and contributions are made to their trust funds. AEP sponsors various defined contribution Contributions are expensed as paid as part of retirement savings plans eligible to substantially the cost of active mining operations and were not all non-United Mine Workers of America (UMWA) material in 2002, 2001 and 2000. In July 2001, U.S. employees. These plans include features OPCo sold certain coal mines in Ohio and West under Section 401(k) of the Internal Revenue Virginia. Code and provide for company matching
- 15. Stock-Based Compensation:
The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) was approved by shareholders at AEP s annual meeting in 2000 and authorizes the use of 15,700,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. The Plan was adopted in 2000. Under the Plan, the exercise price of all stock option grants must equal or exceed the market price of AEP s common stock on the date of grant. AEP generally grants options that have a ten-year life and vest, subject to the participant s continued employment, in approximately equal 1/3 increments on January 1st following L-64
the first, second and third anniversary of the grant date. CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled or expired. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date. A summary of AEP stock option transactions in fiscal periods 2002, 2001 and 2000 is as follows: 2002 2001 2000 weighted Weighted weighted Average Average Average Options Exercise options Exercise options Exercise (in thousands) Price (in thousands) Price (in thousands) Price outstanding at beginning of year 6,822 $37 6,610 $36 825 S40 Granted 2,923 $27 645 $45 6,046 $36 Exercised (600) $36 (216) $38 (26) S36 Forfeited (358) $41 (217) $37 (235) $39 outstanding at end of year -87 8 S34 $37 661Q $36 options exercisable at end of year 2.4E $36 3-9-5 $43 5&8 $41 weighted average Exercise price of options:
-Granted above Market Price $27 N/A N/A -Granted at Market Price $27 $45 $36 The following table summarizes information about 2002 2001 (in millions 2000 AEP stock options outstanding at December 31, except per share amounts)
Net (loss) income: 2002: As reported S (519) S 971 S 267 ODtionS outstanding Pro forma (528) 959 264 Basic (loss) earnings Range of per share: Exercise Number Life in Exercise As reported S(1.57) S3.01 $0.83 Prices outstanding- Years Price Pro forma (1.59) 2.98 0.82 S27.06 35.625 8,047,058 8.4 S 32.54 Diluted (loss) 40.69 49.00 739.483 7.1 44.84 earnings per share: S27.06 49.00 8.786.541 8.3 S 33.58 AS reported S(1.57) $3.01 $0.83 Pro forma (1.59) 2.97 0.82 Ootions Exercisable Range of The proceeds received from exercised stock Exercise Number weighted-Average Prices outstanding Exercise Price options are included in common stock and paid-in
$27.06 35.625 2,230,000 $35.51 capital.
40.69 49.00 251.327 43.66
$27.06 49.00 2.481.327 $36.33 The pro forma amounts are not representative cf If compensation expense for stock options had the effects on reported net income for future been determined based on the fair value at the years.
grant date, AEP net income and earnings per share would have been the pro forma amounts shown in the following table: L-65
The fair value of each option award is estimated
- Coal mining, bulk commodity barging on the date of grant using the Black-Scholes operations and other energy supply option-pricing model with the following weighted related businesses average assumptions used to estimate the fair value of AEP options granted: Energy Delivery
- Domestic electricity transmission Risk Free Interest 2002 2001 2000
- Domestic electricity distribution Rate 3.53% 4.87% 5.02%
Expected Life- 7 years 7 years 7 years Other Expected volatility 29.78% 28.40% 24.75% Expected Dividend Energy services Yield 6.15% 6.05% 6.02% weighted average fair Segment results of operations for the twelve value of opt-ions: months ended December 31, 2002, 2001 and
-Granted above 2000 are shown below. These amounts include Market Price $4.58 N/A N/A certain estimates and allocations where -Granted at Market Price $4.37 $8.01 $5.50 necessary.
- 16. Business Segments: We have used earnings before interest and income taxes (EBIT) as a measure of segment In2000, AEP reported the following four business operating performance. The EBIT measure is segments: Domestic Electric Utilities; Foreign total operating revenues net of total operating Energy Delivery; Worldwide Energy Investments; expenses and other income and deductions from and Other. With this structure, our regulated income. It differs from net income in that it does domestic utility companies were considered not take into account interest expense, income single, vertically-integrated units, and were taxes and the effect of discontinued operations, reported collectively in the Domestic Electric extraordinary items and the cumulative effect of a Utilities segment. change in accounting principle. EBIT is believed to be a reasonable gauge of results of operations.
In 2001 and 2002, we moved toward a goal of By excluding interest expense and income taxes, functionally and structurally separating our EBIT does not give guidance regarding the businesses. The ensuing realignment of our demand of debt service or other interest operations resulted in our current business requirements, or tax liabilities or taxation rates. segments, Wholesale, Energy Delivery and Other. The effects of interest expense and taxes on The business activities of each of these segments overall corporate performance can be seen in the are as follows: Consolidated Statements of Operations. By excluding discontinued operations, extraordinary Wholesale items, and the cumulative effect of changes in Generation of electricity for sale to retail accounting principles, EBIT gives more focused and wholesale customers guidance on segment operating performance.
- Gas pipeline and storage services
- Marketing and trading of electricity, gas, coal and other commodities L-66
Energy Reconciling AEP Year wholesale Delivery other Adiustments consolidated (in millions) 2002 Revenues from: External unaffiliated customers $10,988 S 3,551 S 16 S - $14,555 Transactions with other operating segments 2,314 20 46 (2,380) - Segment EBIT 645 970 (549) - 1,066 Depreciation, depletion and amortization expense 842 519 16 - 1,377 Total assets 22,622 11,624 248 247(a) 34,741 Investments in equity method subsidiaries 115 - 57 - 172 Gross property additions 1,072 638 12 - 1,722 2001 Revenues from: External unaffiliated customers S 9,297 S 3,356 S 114 S - $12,767 Transactions with other operating segments 2,708 20 1,155 (3,883) - Segment EBIT 1,302 986 42 - 2,330 Depreciation, depletion and amortization expense 597 632 14 - 1,243 Total assets 21,947 12,455 220 4,675(a) 39,297 Investments in equity method subsidiaries 242 - 370 - 612 Gross property additions 610 844 200 - 1,654 2000 Revenues from: External unaffiliated customers S 7,834 $3,174 S 105 S - $11,113 Transactions with other operating segments 1,726 2 750 (2,478) - Segment EBIT 686 1,017 89 - 1,792 Depreciation, depletion and amortization expense 556 506 29 - 1,091 Total assets 24,172 14,876 2,625 4,960(a) 46,633 Investments in equity method subsidiaries 140 - 296 - 436 Gross property additions 366 961 141 - 1,468 (a) Reconciling adjustments for Total Assets include Assets Held for sale and/or Assets of Discontinued operations Of the registrant operating company subsidiaries, all of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo s results of operations are reported in AEGCo s financial statements. L-67
Twelve Months Ended Twelve Months Ended December 31. 2002 December 31.2001 Segment Segment Revenues EBIT Total Assets Revenues EBIT Total Assets (in thousands) (in thousands) Wholesale Segment APCo $1,220,381 $215,735 $2,586,966 $1,189,223 $164,844 $2,505,877 CSPCo 907,882 282,974 1,762,074 867,100 232,372 1,742,328 l&M 1,205,043 42,410 3,160,575 1,212,587 117,396 3,027,509 KPCo 246,629 6,568 591,655 247,842 4,935 507,516 OPCo 1,523,452 364,071 2,861,415 1,545,392 240,128 2,820,995 PSO 518,100 34,322 840,374 695,123 52,086 827,235 SWEPCo 736,484 70,547 1,082,251 768,322 82,409 1,127,331 TCC 1,135,946 395,060 3,117,447 1,265,655 303,966 2,847,743 TNC 377,387 (58,930) 376,308 387,422 7,930 371,031 Energy Delivery Segment APCo $ 594,089 $217,360 $2,040,881 $ 595,036 $213,733 $1,976,908 CSPCo 492,278 63,071 991,166 483,219 130,503 980,060 l&M 321,721 170,342 1,426,616 314,410 111,206 1,366,553 KPCo 132,054 51,697 573,021 131,183 54,033 491,532 OPCo 589,673 71,225 1,595,617 552,713 118,261 1,573,078 PSO 275,547 69,543 936,316 261,877 79,787 921,676 SWEPCo 348,236 107,081 1,126,424 333,004 107,197 1,173,345 TCC 554,547 148,918 2,238,991 473,182 109,587 2,045,287 TNC 73,353 53,995 500,867 169,036 33,226 493,844 Registrant Subsidiaries Company Total APCo $1,814,470 $433,095 $4,627,847 $1,784,259 $378,577 $4,482,785 CSPCo 1,400,160 346,045 2,753,240 1,350,319 362,875 2,722,368 l&M 1,526,764 212,752 4,5B7,191 1,526,997 228,602 4,394,062 KPCo 378,683 58,265 1,164,676 379,025 58,968 999,048 OPCo 2,113,125 435,296 4,457,032 2,098,105 358,389 4,394,073 PSO 793,647 103,865 1,776,690 957,000 131,873 1,748,911 SWEPCo 1,084,720 177,628 2,208,675 1,101,326 189,606 2,300,676 TCC 1,690,493 543,978 5,356,438 1,738,837 413,553 4,893,030 TNC 450,740 (4,935) 877,175 556,458 41,156 864,875 L-68
Twelve Months Ended December 31, 2000 Revenues Segment EBIT Total Assets (in thousands) Wholesale Segment APCo $1,184,335 - $154,525 $3,674,081 CSPCo 906,363 235,860 2,481,594 I&M 1,177,190 (146,297) 3,978,360 KPCo 268,529 22,379 759,228 OPCo 1,672,744 289,084 3,976,532 PSO 711,274 54,072 1,011,474 SWEPCo 773,324 27,055 1,302,611 TCC 1,291,588 273,650 3,182,202 TNC 394,860 13,910 466,539 Energy Delivery Segment APCo $ 574,913 $191,560 $2,898,514 CSPCo 398,046 81,896 1,395,897 I&M 311,019 126,241 1,795,748 KPCo 121,346 49,770 735,315 OPCo 467,587 138,418 2,217,443 PSO 245,124 B5,524 1,126,949 SWEPCo 344,950 129,842 1,355,778 TCC 478,814 136,069 2,285,499 TNC 176,204 50,201 620,965 Registrant Subsidiaries Company Total APCo $1,759,253 $346,085 $6,572,595 CSPCo 1,304,409 317,756 3,877,491 I&M 1,488,209 (20,056) 5,774,108 KPCo 389,875 72,149 1,494,543 OPCo 2,140,331 427,502 6,193,975 PSO 956,393 139,596 2,138,423 SWEPCo 1,118,274 156,897 2,658,389 TCC 1,770,402 409,719 5,467,701 TNC 571,064 64,111 1,087,504 L-69
- 17. Risk Management, Financial protection afforded by fuel clause recovery Instruments and Derivatives: mechanisms has either been eliminated by the implementation of customer choice in Risk Manaqement Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, We are subject to market risks in our day to 2002) or frozen by a settlement agreement in day operations. Our risk policies have been Michigan, capped in Indiana and fixed reviewed with the Board of Directors, (subject to future commission action) in West approved by a Risk Executive Committee and Virginia. To the extent all fuel supply for the are administered by the Chief Risk Officer. generating units in these states is not under The Risk Executive Committee establishes fixed price long-term contracts, AEP is subject risk limits, approves risk policies, assigns to market price risk. AEP continues to be responsibilities regarding the oversight and protected against market price changes by management of risk and monitors risk levels. active fuel clauses in Arkansas, Kentucky, This committee receives daily, weekly, and Louisiana, Oklahoma, Virginia and the SPP monthly reports regarding compliance with area of Texas.
policies, limits and procedures. The committee meets monthly and consists of the We enter into currency and interest rate Chief Risk Officer, Chief Credit Officer, V.P. of forward and swap transactions to hedge the Market Risk Oversight, and senior financial currency and interest rate exposures created and operating managers. by commodity transactions. These transactions are marked-to-market to match The risks and related strategies that the change in value in the transactions they management can employ are: hedge which are also marked-to-market. We employ forward contracts as cash flow Risk Description Strategy Price Risk Volatility in Trading and hedges and swaps as cash flow or fair value commodity prices hedging hedges to mitigate changes in interest rates Interest Rate Risk Changes in or fair values on Short-Term Debt and Long-interest rates Hedging Foreign Exchange Fluctuations in term Debt when management deems it Risk foreign currency Trading and necessary. We do not hedge all interest rate rates hedging risk. Credit Risk Non-performance Guarantees on contracts with and counterparfies collateral We employ cash flow forward hedge contracts to lock-in prices on transactions denominated We employ physical forward purchase and in foreign currencies where deemed sale contracts, exchange futures and options, necessary. International subsidiaries use over-the-counter options, swaps, and other currency swaps to hedge exchange rate derivative contracts to offset price risk where fluctuations in debt denominated in foreign appropriate. However, we engage in trading currencies. We do not hedge all foreign of electricity, gas and to a lesser degree other currency exposure. commodities and as a result we are subject to price risk. The amount of risk taken by the Our open trading contracts, including traders is controlled by the management of structured transactions, are marked-to-market the trading operations and the Chief Risk daily using the price model and price curve(s) Officer and his staff. If the risk from trading corresponding to the instrument. Forwards, activities exceeds certain pre-determined futures and swaps are generally valued by limits, the positions are modified or hedged to subtracting the contract price from the market reduce the risk to be within the limits unless price and then multiplying the difference by specifically approved by the Risk Executive the contract volume and adjusting for net Committee. present value and other impacts. Significant estimates in valuing such contracts include AEP is exposed to risk from changes in the forward price curves, volumes, seasonality, market prices of coal and natural gas used to weather, and other factors. generate electricity where generation is no longer regulated or where existing fuel Forwards and swaps are valued based on clauses are suspended or frozen. The L-70
forward price curves which represent a series costs. Also, an energy commodity contracts of projected prices at which transactions can price volatility generally increases as it be executed in the market. The forward price approaches the delivery month. Spot price curve includes the markets expectations for volatility (e.g., daily or hourly prices) can prices of a delivered commodity at that future cause contract values to change substantially date. The forward price curve is developed as open positions settle against spot prices. from the market bid price, which isthe highest When a portion of a curve has been price which traders are willing to pay for a estimated for a period of time and market contract, and the ask or offer price, which is changes occur, assumptions are updated to the lowest price traders are willing to receive align the curve to the market. All fair value for selling a contract. amounts are net of adjustments for items such as credit quality of the counterparty Option contracts, consisting primarily of (credit risk) and liquidity risk. options on forwards and spread options, are valued using models, which are variations on We also mark-to-market derivatives that are Black-Scholes option models. The market- not trading contracts in accordance with related inputs are the interest rate curve, the generally accepted accounting principles. underlying commodity forward price curve, There may be unique models for these the implied volatility curve and the implied transactions, but the curves the Company correlation curve. Volatility and correlation inputs into the models are the same forward prices may be quoted in the market. curves, which are described above. Significant estimates in valuing these contracts include forward price curves, We have developed independent controls to volumes, and other volatilities. evaluate the reasonableness of our valuation models and curves. However, there are Futures and options traded on exchanges inherent risks related to the underlying (primarily oil and gas on NYMEX) are valued assumptions in models used to fair value at the exchange price. open long-term trading contracts. Therefore, there could be a significant favorable or Electricity and gas markets in particular have adverse effect on future results of operations primary trading hubs ordelivery points/regions and cash flows if market prices at settlement and less liquid secondary delivery points. In differ from the price models and curves. North American natural gas markets, the primary delivery points are generally traded Results of Risk ManaqementActivities from Henry Hub, Louisiana. The less liquid gas or power trading points may trade as a The amounts of net revenue margins (sales spread (based on transportation costs, less purchases) in 2002, 2001, and 2000 for constraints, etc.) from the nearest liquid trading activities were: trading hub. Also, some commodities trade 2002 20Q 2000 more often and therefore are more liquid than (in millions) others. For example, peak electricity is a Net Revenue more liquid product than off-peak electricity. Margins $53 $402 $233 Henry Hub gas trades in monthly blocks for up to 36 months and after that only trades in The amounts of revenues recorded in 2002, seasonal or calendar blocks. When this 2001 and 2000 for the registrant subsidiaries occurs, we use our best judgment to estimate were: 2002 2001 2000 the curve values. The value used will be (in thousands) based on various factors such as last trade price, recent price trend, product spreads, APCo $29,044 $ 52,871 S 27,924 CSPCo 24,503 36,120 16,999 location spreads (including transportation I&M 11,833 3,801 19, 130 26,575 KPCo 6, 150 10,704 costs), cross commodity spreads (e.g., heat OPCo 39,114 43,789 26,840 rate conversion of gas to power), time PSO (1,357) (7, 345) 5 233 SWEPCo (4,999) 2,317 1, 562 spreads, cost of carry (e.g., cost of gas TCC (7,708) 10, 500 (1,752) TNC (1098) 1.508 222 storage), marginal production cost, cost of Total 59,3 new entrant capacity, and alternative fuel L-71
The fair value of open trading contracts that are marked-to-market are based on managements best estimates using over-the-counter quotations and exchange prices for short-term open trading contracts, and internally developed price curves for open long-term trading contracts. The following table does not reflect derivative contracts designated as hedges or firm transmission rights contracts. As a result, the totals will not agree to the Consolidated Balance Sheets. The fair values of trading contracts at December 31 are: 2002 2001 Fai r Fai r val ue Val ue (in millions) (in millions) Tradi nq Assets Electricity and other Physicals S 846 S 966 Financials 226 170 Total Trading Assets Gas Physicals S 105 S 196 Financials 685 1,587 Total Trading Assets _9__,8 Trading Liabilities Electricity and other Physicals S (534) S (760) Financials (126) (87) Total Trading Liabilities I S (84 Gas Physicals $ (191) S (38) Financial s (761) (1586) Total Trading Liabilities 5<952) ) The fair values of trading contracts for the registrant subsidiaries at December 31 are: 2002 2001 Fair Fair value value (in thousands) (i n thousands) APCo Trading Assets Electricity and other Physicals S 168,687 S 217,914 Financials 39,585 39,466 Trading Liabilities Electricity and other Physicals S(100,045) $(164,624) Financials (11,375) (17,055) CSPCo Trading Assets Electricity and other Physicals S 113,397 S 133,425 Financials 26,611 24,206 Trading Liabilities Electricity and other Physicals S (67,244) S (98,749) Financials (7,647) (10,433) I&M Trading Assets Electricity and other Physicals S 121,706 S 165,162 Financials 28,474 26,630 Trading Liabilities Electricity and other Physicals S (70,061) S(117,795) Financials (9,258) (12,652) L-72
2002 2001 Fai r Fai r value value (in thousands) (in thousands) KPCo Trading Assets Electricity and other Physicals S 43,532 S 53,651 Financial s 10,216 9,732 Trading Liabilities Electricity and other Physicals S (25,315) S (46,476) Financials (2,935) C4,178) OPco Trading Assets Electricity and other Physicals $158,473 $ 180,989 Financials 35,304 32,997 Trading Liabilities Electric and other Physicals S (89,526) S(132,603) Fi nancials (10,145) (15,937) PSO Trading Assets Electricity Physicals S 8,165 S 47,613 Tradinq Liabilities Electricity Physicals S (4,620) S (45,179) SWEPCo Trading Assets Electricity Physicals S 9,329 S 54,647 Trading Liabilities Electricity Physicals S (5,278) S (51,747) TCC Trading Assets Electricity Physicals S 26,752 $ 62,520 Tradinq Liabilities Electricity Physicals S (21,136) S (58,663) Financials (202) TNC Trading Assets Electricity Physicals $ 6,323 $ 18,567 Trading Liabilities Electricity Physicals S (4,047) $ (17,652) Financials (233) L-73
Credit Risk brokerage accounts with brokers who are registered with the U.S. Commodity Futures AEP limits credit risk by extending unsecured Trading Commission. Brokers and credit to entities based on internal ratings. counterparties require cash or cash-related AEP uses Moody s Investor Service, Standard instruments to be deposited on these and Poors and qualitative and quantitative transactions as margin against open data to independently assess the financial positions. The combined margin deposits at health of counterparties on an ongoing basis. December 31, 2002 and 2001 were $109 This data, in conjunction with the ratings million and $55 million. These margin information, is used to determine appropriate accounts are restricted and therefore are not risk parameters. AEP also requires cash included in Cash and Cash Equivalents on the deposits, letters of credit and parental/affiliate Consolidated Balance Sheets. AEP and its guarantees as security from counterparties subsidiaries can be subject to further margin depending upon credit quality in our normal requirements should related commodity prices course of business. change. We trade electricity and gas contracts with The margin deposits at December 31, 2002 numerous counterparties. Since our open for the registrants were: energy trading contracts are valued based on changes in market prices of the related (inthousands) commodities, our exposures change daily. We believe that our credit and market exposures APCo $1,010 with any one counterparty are not material to CSPCo 673 our financial condition at December31,2002. l&M 727 KPCo 261 At December 31, 2002, less than 7% of our OPCo 1,400 exposure was below investment grade as PSO 91 expressed in terms of Net Mark to Market SWEPCo 105 Assets. Net Mark to Market Assets TCC 121 represents the aggregate difference between TNC 37 the forward market price for the remaining term of the contract and the contractual price Financial Derivatives and Hedaina per counterparty. The following table approximates counterparty credit quality and In the first quarter of 2001, AEP adopted exposure for AEP based on netting across SFAS 133, 'Accounting for Derivative AEP entities, commodities and instruments at Instruments and Hedging Activities, as December 31, 2002: amended. AEP recorded a favorable transition adjustment to Accumulated Other Comprehensive Income of $27 million at Futures, January 1, 2001 in connection with the Forward and Counterparty Swap adoption of SFAS 133. Derivatives included in Credit Quality Contracts options Total the transition adjustment are interest rate (in millions) swaps, foreign currency swaps and AAA/Exchanges $ 26 $ 2 $ 28 AA 307 33 340 commodity swaps, options and futures. A 448 26 474 BBB 700 101 801 Most of the derivatives identified in the trans-Below Investment Grade 107 11 118 ition adjustment were designated as cash flow hedges and relate to foreign operations. Total $15R8 $17 $1.761 Certain derivatives may be designated for We enter into transactions for electricity and accounting purposes as a hedge of eitherthe natural gas as part of wholesale trading fair value of an asset, liability, firm operations. Electricity and gas transactions commitment, or a hedge of the variability of are executed over-the-counter with cash flows related to a variable-priced asset, counterparties or through brokers. Gas liability, commitment, or forecasted trans-transactions are also executed through action. To qualify for hedge accounting, the L-74
relationship between the hedging instrument SFAS 133 are recognized currently in and the hedged item must be documented to earnings through mark-to-market accounting. include the risk management objective and Changes in the fair value of effective cash strategy for use of the hedge instrument. At flow hedges are reported in Accumulated the inception of the hedge and on an ongoing Other Comprehensive Income. Gains and basis, the effectiveness of the hedge is losses from cash flow hedges in other assessed to determine whetherthe hedge will comprehensive income are reclassified to be or is highly effective in offsetting changes earnings in the accounting periods in which in fair value or cash flows of the item being the variability of cash flows of the hedged hedged. Changes in the fair value that result items affect earnings from the ineffectiveness of a hedge under Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on AEP s Consolidated Balance Sheets at December 31, 2002 are: Accumulated Other Comprehensive Hedging Assets Heing Liabilities Income (Loss) After Tax ions) Electricity and Gas $6 $ (8) $ (2) Interest Rate _ (13)* (12) Foreign currency _ (2) 5U163
- Includes $6 million loss recorded in an equity investment.
The following table represents the activity in Other Comprehensive Income (Loss) related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at December 31, 2002: (in millions) AEP consolidated Beginning Balance, January 1, 2002 $ (3) Changes in fair value (56) Reclasses from oci to net loss 43 Accumulated OCI derivative loss, December 31, 2002 S 7(16l) (in thousands) APCo Beginning Balance, January 1, 2002 S (340) Effective portion of changes in fair value (1,310) Reclasses from OCX to net income (270) Accumulated oCI derivative loss, December 31, 2002 Sf1 92) CsPco Beginning Balance, January 1, 2002 $ - Effective portion of changes in fair value 62 Reclasses from OCI to net income -(32) Accumulated ocI derivative loss, December 31, 2002 I&N Beginning Balance, January 1, 2002 S(3, 835) Effective portion of changes in fair value 34 Reclasses from OCX to net income 3.515 Accumulated OCi derivative loss, December 31, 2002 S 2&6) KPCO Beginning Balance, January 1, 2002 S (1, 903) Efective portion of changes in fair value 343 Reclasses from OCi to net income 1 882 Accumulated OCI derivative gain, December 31, 2002 2i! oPCo Beginning Balance, January 1, 2002 $ (196) Effective portion of changes in fair value (103) Reclasses from OCI to net income (439) Accumulated OCI derivative loss, December 31, 2002 5 t738) PSO Beginning Balance, January 1, 2002 5 _ Effective portion of changes in fair value 2) Reclasses from OCI to net income Accumulated OCI derivative loss, December 31, 2002 L-75
(in thousands) SWEPCo sepi nning Balance, January 1, 2002 $ - Effective portion of changes in fair value 1 Recl asses from OCI to net income (49) Accumul ated oCI derivative loss, December 31, 2002 TCC Meinning Balance, January 1, 2002 Ef ective portion of changes in fair value 30 Recl asses from OCI to net income (66) Accumul ated OCi derivative loss, December 31, 2002 S 53) TNC Bemi nning Balance, January 1, 2002 Effective portion of changes in fair value 3 Rec asses from OCI to net income Ii8) Accumulated oci derivative loss, December 31, 2002 Approximately $9 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2002 are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is five years. Financial Instruments Market Valuation of Non-Derivative Financial Instrument The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. The fair values of Long-term Debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. The book values and fairvalues of significant financial instruments forAEP and its registrant subsidiaries at December 31, 2002 and 2001 are summarized in the following tables. 2002 2001 Book value Fair value Book value Fair value (in millions) (in millions) AEP Long-term Debt S 10,125 S 10,470 S 9,505 S 9,542 Preferred Stock 84 77 95 93 Trust Preferred Securities 321 324 321 321 (in thousands) (in thousands) AEGCo Long-term Debt S 44,802 S 48,103 S 44,793 S 45,268 APCo Long-term Debt $1,893,861 $1,953,087 $1,556,559 $1,439,531 Preferred Stock 10,860 9,774 10,860 10,860 CSPco Long-term Debt S 621,626 S 643,715 S 791,848 S 802,194 Preferred stock - - 10,000 10,100 I&M Long -term Debt $1,617,062 S1,673,363 $1,652,082 $1,672,392 Preferred stock 64,945 58,948 64,945 62,795 KPCo Long-term Debt S 466,632 S 475,455 S 346,093 S 350,233 oPCo Long-term Debt S1,067,314 S1,095,197 S1,203,841 S1,227,880 Preferred Stock 8,850 7,965 8,850 8,837 L-76
PSO Long-term Debt S 545,437 S 570,761 S 451,129 S 462,903 Trust Preferred securities 75,000 75,900 75,000 74,730 SWEPCo Long-term Debt S 693,448 $ 727,085 $ 645,283 S 656,998 Trust Preferred securities 110,000 110,880 110,000 109,780 TCC Long-term Debt S1,438,565 S1,522,373 $1,253,768 S1,278,644 Trust Preferred Securities 136,250 136,959 136,250 135,760 TNC Long-term Debt S 132,500 $ 144,060 S 255,967 S 266,846 Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value The trust investments which are classified as held for sale for decommissioning and SNF disposal, reported in Other Assets on AEP s Consolidated Balance Sheets, are recorded at market value in accordance with SFAS 115 'Accounting for Certain Investments in Debt and Equity Securities . At December 31, 2002 and 2001, the fair values of the trust investments were $969 million and $933 million, respectively, and had a cost basis of $909 million and $839 million, respectively. The change in market value in 2002, 2001, and 2000 was a net unrealized holding loss of $33 million and $11 million and a net unrealized holding gain of $6 million, respectively.
- 18. Income Taxes:
The details of AEP s consolidated income taxes before discontinued operations, extraordinary items, and cumulative effect as reported are as follows: Year Ended December 31, 2002 2001 2000 (in millions) Federal: Current S 330 $404 S 793 Deferred (192) 60 (236) Total 138 464 557 State: Current 32 61 47 Deferred 30 34 IA) Total 62 95 41 International: current 13 (13) 4 Deferred 1 Total 14 (13) 4 Total Income Tax as Reported Before Discontinued operations, Extraordinary Items and Cumulative Effect S£214 i546 L-60Z L-77
The details of the registrant subsidiaries income taxes as reported are as follows: AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2002 (in thousands) charged (credited) to operating Expenses (net): Current S 6,607 S 99,140 S 81,539 S 66,063 S 680 Deferred (5,028) 17,626 25,771 (19,870) 9,451 Deferred Investment Tax Credits 2 _(3229) (3.096) (7,340) (1.173) Total 1.581 113.537 104.214 38.853 8.958 charged (credited) to Nonoperating Income (net): Current (173) (354) 9,442 3,435 1, 583 Deferred (849) (2,479) 2,949 388 Deferred Investment Tax Credits (3.363) (1.408) (174) (400) (67 Total (3.536) (2.611) 6.789 5. 984 1.904 Total Income Tax as Reported Si10-W26 1S 44,83 OPCo PS0 SWEPCo TCC TNC Year Ended December 31, 2002 (in thousand s) Charged (credited) to operating Expenses (net): Current S 86,026 S(49,673) S 41,354 $ 30,495 S 109 Deferred 30,048 75,659 (3,134) 113,726 (10,652) Deferred Investment Tax credits (2.493) (1.791) (4,524) (5,207) (1 271) Total 113. 581 24. 195 33. 696 139.014 charged (credited) to Nonoperating Income (net): Current 2,732 (1,812) 1,772 3,223 1,334 Deferred 15,962 (71) (1,623) Deferred Investment Tax credits (684) Total 18.010 _(1. 812) 1.772 3. 152 (289) Total Income Tax as Reported IM-M S-11z-lu AEGCO APCo CSPCo I&M KPCO Year Ended December 31, 2001 (in thousands) charged (Credited) to operating Expenses (net): Current S 9,126 $ 71,623 S 88,013 S 107,286 S 7,726 Deferred (6,224) 27,198 14,923 (45,785) 2,812 Deferred Investment Tax credits (3.237) (3.899) (7.377) (1.180) Total 2.902 95. 584 99.037 54.124 9. 358 charged (Credited) to Nonoperating Income (net): Current (56) (19,165) (13,803) (10,590) (2,725) Deferred 21,832 17,885 16,580 3,481 Deferred Investment Tax credits (3.414) 2(1,528) (159) (947) (72) Total (35470) 1. 139 5.043 684 Total Income Tax as Reported S 96,72 5102ISMi OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2001 (in thousands) charged (credited) to operating Expenses (net): Current S(62,298) S 53,030 $ 77,965 S 190,671 S 19,424 Deferred 166,166 (16,726) (31,396) (72,568) (11,891) Deferred Investment Tax Credits (2.495) (1.791) (4.453) (S.207) (1.271) Total 101.373 34.513 42.116 112.896 6. 262 Charged (credited) to Nonoperating Income (net): Current (21,600) 352 542 (398) (691) Deferred 20,014 Deferred Investment Tax credits (794) Total (2. 380) 352 542 (398) (691) Total Income Tax as Reported S 34,85S4268S 1,9 L-78
AEGCo APCo CSPCo I&M KPCO Year Ended December 31, 2000 (in thousands) Charged (Credited) to operating Expenses (net): Current S 8,746 $129,165 $120,494 S 134,796 S 17,878 Deferred (5,842) 3,838 (7,746) ( 126,748) 2,521 Deferred Investment Tax Credits (2.947) (3.379) _ (7,524) (1. 187) Total _ 2.904 130.056 109,369 _ 524 19.212 charged (credited) to Nonoperating Income (net): Current (44) 327 3,777 2, 950 (50) Deferred 4,764 3,683 1, 569 1,244 Deferred Investment Tax credits (3 396) (l.968) (103) (330) (65) Total (3L440) 3. 12 3 7. 357 = 4.189 1.129 Total Income Tax as Reported OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2000 (in thousands) charged (Credited) to operating Expenses (net): current $ 259,608 S 11,597 S 16,073 S 89,403 S 6,774 Deferred (70,263) 25,453 14,653 16,263 9,401 Deferred Investment Tax credits (118 24) 1.791) (4 482) 50 20 ) (1.271) Total 187. 521 35. 259 26.244 100.459 14.904 charged (Credited) to Nonoperating Income (net): Current 15,426 (1,306) (1,476) (5,073) (222) Deferred 4,307 - - - (1,237) Deferred Investment Tax credits (1,575) Total 18,158 (1.306) 1.7) (5,073) (1.459) Total Income Tax as Reported S-205-6S 9 53 4,9344 The following is a reconciliation for AEP Consolidated of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of income taxes reported. Year Ended December 31. 2002 2001 2000 (in millions) Net Income (Loss) 5(519) $ 971 $267 Discontinued Operations (net of income tax of $73 million in 2002, $22 million in 2001 and $5 million in 2000) 190 (86) (122) Extraordinary Items (net of income tax of $20 million in 2001 and $44 million in 2000) 50 35 cumulative Effect of Accounting Change (net of income tax of $2 million in 2001) 350 (18) Preferred stock Dividends 11 10 11 Income Before Preferred Stock Dividends of Subsidiaries 32 927 191 Income Taxes Before Discontinued operations, Extraordinary Items and Cumulative Effect 214 546 602 Pre-Tax Income w9M Income Taxes on Pre-Tax Income at Statutory Rate (35%) S 86 S 516 $278 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 32 48 77 Corporate owned Life Insurance 4 247 Investment Tax Credits (net) (35) (37) (36) Tax Effects of International operations 123 (12) (1) Energy Production credits (14) Merger Transaction Costs 49 State Income Taxes 40 62 26 other (18) (35) (38) Total Income Taxes as Reported Before Discontinued operations, Extraordinary Items and Cumulative Effect S 214 S 546 M62 Effective Income Tax Rate 1B7L1% _Z31A% M IN9 L-79
Shown below is a reconciliation for each AEP registrant subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported. AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2002 (in thousands) Net Income S 7,552 $205,492 5181,173 S 73,992 S 20,567 Income Taxes _(1.955) 110.926 111.003 44.837 10.862 Pre-Tax Income L 559 Ln§="1 rn$=7 ii Li3,42 Income Tax on Pre-Tax Income at Statutory Rate (35%) S 1,959 $110,746 $102,262 S 41,590 S 11,000 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 870 3,082 2,899 21,812 2,057 Corporate owned Life Insurance (93) 719 268 305 Nuclear Fuel Disposal Costs - - (3,814) Allowance for Funds used During construction (446) - - (3,453) Rockport Plant unit 2 Investment Tax credit (748) Removal costs (735) Investment Tax credits (net) (3,361) (4,637) (3,270) (7,740) (1,240) State Income Taxes 335 6,469 11,387 124 1,058 Other (564) (4.641) (2.994) (3.950) (1.583) Total Income Taxes as Reported S L(1955) 11 S111%M S 4483 S 10,862 Effective Income Tax Rate N. M. Or-i 3fO h 37.7I 3A.6% OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2002 (in thousands) Net Income (Loss) $220,023 S 41,060 S 82,992 S 275,941 S(13,677) Income Taxes 131.591 22,383 35 468 142.166 (12.103) Pre-Tax Income (LOSS) Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) $123,065 S 22,205 S 41,461 S 146,337 $ (9,023) Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 4,227 (583) (2,790) (295) (32) corporate owned Life Insurance (84) Investment Tax Credits (net) (3,177) (1,791) (4,524) (5,207) (1,271) State Income Taxes 18,051 2,639 3,987 2,202 (1,577) other (10.491) (87) (2.666) (871) (200) Total Income Taxes as Reported S 238-3 Effective Income Tax Rate 37.4% 29--9% 3A-% AEGCo APCo CSPCO I&M KPCo Year Ended December 31, 2001 (in thousands) Net Income S 7,875 $161,818 $161,876 S 75,788 S 21,565 Extraordinary LosS - - 30,024 Income Taxes (568) 96.723 102.960 59 167 10.042 Pre-Tax Income S 730S5854 S9486 Income Tax on Pre-Tax Income at Statutory Rate (35%) S 2,557 S 90,489 $103,201 S 47,234 S 11,062 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 230 2,977 2,757 21,224 1,581 Corporate owned Life Insurance _ '450 544 (148) 334 Nuclear Fuel Disposal Costs - - - (3,292) Allowance for Funds Used During Construction (1,078) - - (1,606) Rockport Plant Unit 2 Investment Tax credit 374 - _ _ Removal costs (420) Investment Tax Credits (net) (3,414) (4,765) (4,058) (8,324) (1,252) State Income Taxes 1,050 9,613 5,727 6,137 318 other (287) (2.041) (5.211) (2.058) (1.581) Total Income Taxes as Reported S M i=31 39396 A398% 310,04 Effective Income Tax Rate N.M. 37.4% 3S4d3% 43L-" L-80
OPCo PSO SWEPCO TCC TNC Year Ended December 31, 2001 (in thousands) Net Income S 147,445 S 57,759 S 89,367 S 182,278 S 12,310 Extraordinary Loss 18, 348 - 2,509 - Income Taxes 98. 993 34. 865 42 658 112 498 5.571 Pre-Tax Income i 92,62 Dim,02 UM9,25M _78 Income Tax on Pre-Tax Income at Statutory Rate (35X) S 92,675 S 32,418 S 46,209 S 104,050 S 6,258 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 7,972 1,127 (501) 8,477 1,463 Corporate owned Life Insurance 1,852 - - - Investment Tax Credits (net) (3,289) (1,791) (4,453) (5,207) (1,271; State Income Taxes 9,752 5,137 5,451 9,652 1,283 other (9.969) -- 2,026) t4048) (4.474) 2 .62' Total Income Taxes as Reported ii --Aq8,93 S-34,86 1 42,65 Effective Income Tax Rate 37.A% 3l76% 3Z.3% 37.8% 31.2% AEGCo APCo CSPCO I&M KPCO Year Ended December 31, 2000 (in thousands) VjA.M ) 5_A1_3D4~~~~~~~~~~~Ok Net Income (Loss) S 7,984 S 73,844 S 94,966 S(132,032) S 20,763 Extraordinary (Gains) Loss (1,066) 39,384 -- Income Tax Benefit - (7,872) (14,148) - - Income Taxes (536) 133,179 116 726 4.713 20 341 Pre-Tax Income (Loss) Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) S 2,607 S 69,330 S 82,925 S (44,562) S 14,386 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 452 7,606 10,529 20,378 1,827 Corporate owned Life Insurance - 54,824 29,259 42,587 5,149 Nuclear Fuel Disposal Costs _ - - (3,957) Allowance for Funds used During Construction (1, 070) - - (2,211) Rockport Plant Unit 2 Investment Tax credit 374 Removal Costs (1,197) (420) Investment Tax Credits (net) (3,396) (4,915) (3,482) (7,854) (1,252) State Income Taxes 784 9,950 89 6,004 1,597 Other (287) (2.419) (2. 594) (S. 672) (946) Total Income Taxes as Reported i__C53 ) 5133,172 Effective Income Tax Rate N MR 6Zv2% 49-% NoM_ 49.5% OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2000 (in thousand s) Net Income S 83, 737 S 66,663 S 72,672 S 189,567 S 27,450 Extraordinary LOSS 40,157 Income Tax Benefit (21,281) Income Taxes 205.679 33 953 24 768 95 386 13,445 Pre-Tax Income 5-3QZ Income Tax on Pre-Tax Income at Statutory Rate (35,) S 107,902 S 35,216 $ 34,104 $ 99,734 S 14,313 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 27,577 695 (1,012) 7,556 1,204 Corporate owned Life Insurance 84,453 Investment Tax Credits (net) (3,398) (1,791) (4,482) (5,207) (1,271) state Income Taxes (1,988) 3,037 1,650 2,296 other _(8,867) (3-204) (5,492) (8.993) (801) Total Income Taxes as Reported S33D953 24,768 Effective Income Tax Rate 66.7% 33i-% 32.9% L-81
The following tables show the elements of the net deferred tax liability and the significant temporary differences for AEP Consolidated and each registrant subsidiary: December 31. 2002 2001 (in millions) Deferred Tax Assets $ 2,189 $ 1,216 . Deferred Tax Liabilities (6, 105) (5, 71 ) Net Deferred Tax Liabilities $(3 ,916) Property Related Temporary Differences $(3,612) $(3,674) Amounts Due From Customers For Future Federal Income Taxes (360) (245) Deferred state Income Taxes (422) (314) Transition Regulatory Assets (234) (268) Regulatory Assets Designated for securitization (310) (332) Asset Impairments and Investment value Losses 417 Deferred Income Taxes on other comprehensive Loss 326 3 All other (net) 279 330 Net Deferred Tax Liabilities AEGCO APCo CSPCo I&M KPCo December 31, 2002 (in thousands) Deferred Tax Assets S 73,094 S 213,972 S 72,990 S 348,672 S 36,948 Deferred Tax Liabilities (102.096) (915.773) (510.761) (704.869) (215.261) Net Deferred Tax Liabilities S f29,= S(0,0) Sk437-M7) S3617 Property Related Temporary Differences S (74,291) S(555,824) S(331,381) S(343, 587) S(127,073) Amounts Due From Customers For Future Federal Income Taxes 7,626 (58,246) (8,895) (38,752) (20,488) Deferred state Income Taxes (5,119) (77,693) (23,448) (52,528) (28,722) Transition Regulatory Assets (28,735) (71,752) Asset Impairments and Investment value Losses 18 215 225 4 Deferred Income Taxes on other comprehensive Loss - 38,823 31,961 21,800 5,089 Net Deferred Gain on sale and Leaseback-Rockport Plant Unit 2 38,866 - 25,860 Accrued Nuclear Decommissioning Expense - - 65,856 Deferred Fuel and Purchased Power - (1,878) (273) (13,144) 415 Deferred cook Plant Restart Costs - - (14,000) Nuclear Fuel (5,153) All other (net) 3 916 (18. 266) (34,.198) (2.774) (7.538) Net Deferred Tax Liabilities SQ l) g4UU1) 5 6 ) 5 (17, 31) OPCo PSO SWEPCo TCC TNC December 31, 2002 (in thousands) Deferred Tax Assets S 155,334 S 70,649 S 82,113 S 130,210 $ 35,970 Deferred Tax Liabilities (949.721) (412.045) (423.177) (1L391.46) (153.491) Net Deferred Tax Liabilities S(620,634) 5t3410338) 5(31,821) S (709,246) S(142,034) Property Related Temporary Differences S(620,634) S(303,888) S(315,821) S (709,246) S(142,034) Amounts Due From Customers For Future Federal Income Taxes (53,256) 9,490 (4,078) (198,595) 5,726 Deferred State Income Taxes (46,990) (57,911) (48,372) (66,333) (4,080) Transition Regulatory Assets (131, 833) Asset Impairments and Investment value Losses 615 - 14,996 Deferred Income Taxes on other comprehensive Loss 39,246 29,332 28,906 39,394 16,565 Deferred Fuel and Purchased Power 540 (28,696) 3,192 2,655 (9,933) Regulatory Assets Designated For Securitization - - - (310,410) - All other (net) 17 925 10 277 (4 891 .(18,717) 1 239 Net Deferred Tax Liabilities 5(9438) (31;9) 531;064) (,625)S172) L-82
AEGCo APCO CSPCO I&M KPCo December 31, 2001 (in thousands) Deferred Tax Assets S 75,856 S 162,334 S 74,767 S 332,225 S 30,927 Deferred Tax Liabilities _f103 831) *J865.909) (518.489) (732.756) -(19-9231) Net Deferred Tax Liabilities S 273) SU16M,3A) Property Related Temporary Differences S (70,581) $(530,298) $(323,139) S(306,151) S(118,147) Amounts Due From Customers For Future Federal Income Taxes 9,292 (55,206) (9,839) (46,756) (20,215) Deferred State Income Taxes (3,822) (56,747) (8,968) (38,015) (25, 267) Transition Regulatory Assets - (34,783) (78,298) Deferred Income Taxes on other comprehensive LOSS - 183 - 2,065 1,025 Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2 40,816 _ 27, 157 Accrued Nuclear Decommissioning Expense - -43, 707 Deferred Fuel and Purchased Power - (4,106) (39) (26,270) 57 Deferred Cook Plant Restart Costs - - (28,000) Nuclear Fuel - - - (16,062) All other (net) (3.680) (22,618) (23, .439) (12.206) (5.757) Net Deferred Tax Liabilities 5 1 570357) 50493, EZ2) yaocui53) la-GM30) OPCo PSO SWEPCo TCC TNC December 31, 2001 (in thousands) Deferred Tax Assets S 135,938 S 59,421 S 56,189 $ 130,863 S 22,888 Deferred Tax Liabilities (933.827) (356.298) (425,970) (1.294.658) (167,937) Net Deferred Tax Liabilities S (797, 8S1)0,199 (6,441) (7,174) IL145 74) Property Related Temporary Differences S(595,974) S(320,900) S(362,884) S (808,922) S(149,309) Amounts Due From Customers For Future Federal Income Taxes (61,130) 10,199 (6,441) (70,174) 4,757 Deferred state Income Taxes (18,440) (35,038) (48,729) (66,333) (4,079) Transition Regulatory Assets (154,947) Deferred Income Taxes on other comprehensive Loss 106 Deferred Fuel and Purchased Power 12 3,052 (2,778) 18,032 (11,756) Provision for Mine shutdown Costs 20,323 Regulatory Assets Designated For securitization - - (332,198) - All other (net) - 12 45 810 451 51.5O l 9,800 15.338 Net Deferred Tax Liabilities W---;8) MSl26;7) S(369,781) S(,6;9)S15iQ-M) We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent s Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments. Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations. COLI Litigation - On February 20, 2001, the U.S. District Court forthe Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax returns related to its COLI program. AEP had filed suit to resolve the IRS assertion that interest deductions forAEP s COLI program should not be allowed. In 1998 and 1999 the Company paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending the resolution of this matter. As a result of the U.S. District Court s decision to deny the COLI interest deductions, net income was reduced by $319 million in 2000. The Company has filed an appeal of the U.S. District Court s decision with the U.S. Court of Appeals for the 6t Circuit. The earnings reductions recorded in 2000 for affected registrant subsidiaries were as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 L-83
The Company joins in the filing of a consolidated federal income tax return with its affiliated companies in the AEP System. The allocation of the AEP System s current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determing their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.
- 19. Basic and Diluted Earnings Per Share:
The calculation of AEP s basic and diluted earnings (loss) per common share (EPS) is based on the amounts of Net Income (Loss) and weighted average common shares shown in the table below: 2002 2001 2000 (in millions except per share amounts) Income: Income Before Discontinued operations, Extraordinary Items and Cumulative Effect $ 21 S 917 $ 180 Discontinued operations (190) 86 122 Income (Loss) Before Extraordinary Item And cumulative Effect (169) 1,003 302 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) 1519) $ 971 $ 267 weighted Average shares: Average Common shares outstanding 332 322 322 Assumed conversion of Dilutive stock options (see Note 15) 1 Diluted Average common shares Outstandi ng 332 __3 -322 Basic and Diluted Earnings Per common Share: Income Before Discontinued operations, Extraordinary Items and cumulative Effect $ 0.06 $2.85 $0.56 Discontinued operations (0.57) 0.26 0.38 Income (Loss) Before Extraordinary Item and Cumulative Effect (0.51) 3.11 0.94 Extraordinary Losses (net of tax): Discontinuance of Regulatory Accounting For Generation (0.15) (0.11) Loss on Reacquired Debt (0.01) cumulative Effect of Accounting change (net of tax) (1.06) 0.06
${i.5Z) SI.D2 L-84
The assumed conversion of stock options does not affect net earnings (loss) for purposes of calculating diluted earnings per share. AEP s basic and diluted EPS are the same in 2002, 2001 and 2000 since the effect on weighted average common shares outstanding is minimal. Had AEP recognized net income in fiscal 2002, incremental shares attributable to the assumed exercise of outstanding stock options would have increased diluted common shares outstanding by 398,000 shares. Options to purchase 8.8 million, 0.7 million and 6.4 million shares of common stock were outstanding at December 31, 2002, 2001 and 2000, respectively, but were not included in the computation of diluted earnings per share because the options exercise prices were greater than the year-end market price of the common shares and, therefore, the effect would be antidilutive. In addition, there is no effect on diluted earnings per share related to our equity units (issued in 2002) unless the market value of AEP common stock exceeds $49.08 per share. There were no dilutive effects from equity units at December31,2002. If our common stock value exceeds $49.08 we would apply the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contracts are used to repurchase outstanding shares. Also see Note 27.
- 20. Supplementary Information:
Year Ended December 31, 2002 2001 2000 (in millions) AEP Consolidated Purchased Power Ohio valley Electric Corporation (44.2% owned by AEP System) $142 $127 $86 cash was paid for: Interest (net of capitalized amounts) $792 $972 $842 Income Taxes $336 $569 $449 Noncash Investing and Financing Activities: Acquisitions under capital Leases $ 6 $17 $118 Assumption of Liabilities Related to Acquisitions $ 1 $171 Exchange of communication Investment for Common stock _ $5 The amounts of power purchased by the registrant subsidiaries from Ohio Valley Electric Corporation, which is 44.2% owned by the AEP System, for the years ended December 31, 2002, 2001, and 2000 were: APCo CSPCo I&M oPCo (in thousands) Year Ended December 31, 2002 $53,386 $14,885 $23,282 $50,135 Year Ended December 31, 2001 45,542 12,626 20,723 47,757 Year Ended December 31, 2000 30,998 8,706 15,204 31,134
- 21. Power and Distribution Projects: Investments in power projects that are 50% or less owned are accounted for by the equity Power Projects method and reported in Investments in Power and Distribution Projects on AEP s AEP owns interests of 50% or less in Consolidated Balance Sheets (see 'Eastex domestic unregulated power plants with a within the Assets Held for Sale section of capacity of 1,483 MW located in Colorado, Note 13), except for Eastex Cogeneration Florida and Texas. In addition to the which, due to its structure, is consolidated.
domestic projects, AEP has equity interests in At December 31, 2002, six domestic power international power plants totaling 1,113 MW. projects and three international power investments are accounted for under the L-85
equity method. The six domestic projects are losses from operations and AEP s investment combined cycle gas turbines that provide has been affected by the devaluation of the steam to a host commercial customer and are Brazilian Real. In December 2002, AEP considered either Qualifying Facilities (QFs) recorded an otherthan temporary impairment or Exempt Wholesale Generators (EWGs) totaling $141.1 million (after federal income under PURPA. The three international power tax benefit of $76 million) of its 44% equity investments are classified as Foreign Utility investment in Vale and its 20% equity interest Companies (FUCO) underthe Energy Policies in Caiua. See 'Grupo Rede Investment Act of 1992. Two of the international within the Investment Values section of Note investments are power projects and the other 13 "Asset Impairments and Investment Value international investment is a company which Losses, for further information on the 2002 owns an interest in four additional power impairment of AEP s Vale and Caiua projects. All of the power projects accounted investments. for under the equity method have unrelated third-party partners. 22. Leases: Seven of the above power projects have Leases of property, plant and equipment are project-level financing, which is non-recourse for periods up to 99 years and require to AEP. AEP or AEP subsidiaries have payments of related property taxes, guaranteed $58 million of domestic maintenance and operating costs. The partnership obligations for performance under majority of the leases have purchase or power purchase agreements and for debt renewal options and will be renewed or service reserves in lieu of cash deposits. replaced by other leases. Distribution Projects Lease rentals for both operating and capital leases are generally charged to operating AEP owns a 44% equity interest in Vale, a expenses in accordance with rate-making Brazilian electric operating company which treatment for regulated operations. Capital was purchased for a total of $149 million. On leases for non-regulated property are December 1, 2001 AEP converted a $66 accounted for as if the assets were owned million note receivable and accrued interest and financed. The components of rental into a 20% equity interest in Caiua (Brazilian costs are as follows: electric operating company), a subsidiary of Vale. Vale and Caiua have experienced L-86
AEP AEGCo APCO CSPCo I&M KPCo OPCo Year Ended December 31, 2002 (in thousands) Lease Payments on operating Leases $346,000 $76,143 S 6,634 S 5,209 S110,833 S 1,597 s68,816 Amortization of capital Leases 65,000 238 9,729 6,010 8,319 2,171 12,637 Interest on capital Leases 14 000 19 2.240 1.717 2.221 469 4.501 Total Lease Rental Costs _6 4QQAOOS18.6Q3 j1Za36 1121373 4.Z31 585-9-5A Pso SWEPCO TCC TNC Year Ended December 31, 2002 (in thousands) Lease Payments on Operating Leases S 4,403 $3,240 $ 7,184 S 1,981 Amortization of Capital Leases Interest on Capital Leases Total Lease Rental Costs AEP AEGCo APCO CSPCO I&M KPCo OPCo Year Ended December 31, 2001 (in thousands) Lease Payments on Operating Leases $293,000 $76,262 S 6,142 S 7,063 $104,574 S 1,191 $63, 913 Amortization of capital Leases 82,000 281 12,099 7,206 17,933 2,740 14,443 Interest on Capital Leases 22.000 55 3,719 2.396 4.424 808 Total Lease Rental Costs I765j8 577-.030 S16-66i S126 931 SEL4,174 Pso SWEPCo TCC TNC Year Ended December 31, 2001 (in thousands) Lease Payments on operating Leases S 4,010 S 2,277 $ 5,948 $ 1,534 Amortization of capital Leases Interest on capital Leases Total Lease Rental Costs 5_227Z L S48 AEP AEGCo APCO CSPCo I&M KPCo OPCo Year Ended December 31, 2000 (in thousands) Lease Payments on operating Leases $246,000 $73,858 S 7,128 S 7,683 S 81,446 $ 1,978 $51,981 Amortization of Capital Leases 118,000 281 13,900 7,776 26,341 3,931 37,280 Interest on Capital Leases 36.000 55 3.930 2.690 10 908 1.054 9.584 Total Lease Rental Costs a.-I" 524,9 598-845 Pso SWEPCo TCC TNC Year Ended December 31, 2000 (in thousands) Lease Payments on Operating Leases S 3,269 $ 1,401 $ 5,410 S 1,210 Amortization of capital Leases Interest on Capital Leases _14- _ Total Lease Rental Costs S 3MUi Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: AEP AEGCO APCo CSPCo I&M KPCo Year Ended December 31, 2002 (in thousands) Property, Plant and Equipment Under Capital Leases Production S 40,000 S 1,793 S 3,368 S 6,380 S 5,728 S 1,138 Distribution 15,000 14,589 other: Mining Assets and other 687.000 67.395 46.791 70,140 14.258 Total Property, Plant and Equipment 742,000 1,793 70,763 53,171 90,457 15,396 Accumulated Amortization 299.000 1.294 37.452 26.551 41. 141 8.168 Net Property, Plant and Equipment under capital Leases S443L,00 S 499 $3X111 Skv62 S 49,619 obligations under capital Leases: Noncurrent Liability S170,000 S 301 $23,991 $21,643 S 42,619 S 5,093 Liability Due within one Year 58.000 198 9.598 5.967 8. 229 2.155 Total obligations under Capital Leases S228.00Q S 4A99 S33,-58 V2761D S 7,248 L-87
oPco SWEPCo Year Ended December 31, 2002 (in thousands) Property, Plant and Equipment under capital Leases Production S 21,360 S - Distribution other: Mining Assets and other 103.018 45.699 Total Property, Plant and Equipment 124,378 45,699 Accumulated Amortization. 63.810 45. 699 Net Property,. Plant and Equipment under Capital Leases obligations under Capital Leases: Noncurrent Liability S 51,266 S - Liability Due within one Year 14,360 Total obligations under Capital Leases S 65,62 AEP AEGCO APCO CSPCo I&M KPCo oPco Year Ended December 31, 2001 (in thousands) Property, Plant and Equipment Under capital Leases Production $ 39,000 S 1,983 S 2,712 S 6,380 S 4,826 S 1,138 S 22,477 Distribution 15,000 - - 14,593 other: Mining Assets and other 723.000 129 82.292 54.999 86.267 17.658 114.944 Total Property, Plant and Equipment 777,000 2,112 85,004 61,379 105,686 18,796 137,421 Accumulated Amortization 250.000 !1. 801 38.745 26.044 43 768 9.213 57.429 Net Property, Plant and Equipment under Capital Leases 557,000 1-3-u S33-M i==UJW SLIR-M obligations under capital Leases: Noncurrent Liability $219,000 $ 76 $33,928 $27,052 S 51,093 $ 6,742 S 64,261 Liability Due within One Year 75.000 235 12.357 7.835 10 840 2.841 16.405 Total obligations Under capital Leases OM9G00 S 311 5-61,9D33 9,583 5_80,666 Future minimum lease payments consisted of the following at December 31, 2002: AEP AEGCo APCO CSPco I&M KPCO oPCo Capi tal (in thousands) 2003 S 70,000 S 249 $12,483 S 7,365 S 10,373 S 2,623 S 17,363 2004 53,000 114 10,515 6,231 9,122 1,957 14,634 2005 37,000 58 6,799 5,279 6,506 1,581 11,442 2006 29,000 31 5,117 3,898 5,561 948 10,220 2007 21,000 29 2,668 2,969 4,024 788 8,694 Later Years 59.000 79 4.829 8.32 10.732 725 20.302 Total Future Minimum Lease Payments 269,000 560 42,411 34,063 46,318 8,622 82,655 Less Estimated Interest Elemen 41,000 61 8.822 6.453 (4.530) 1.374 17.029 Estimated Present value of Future Minimum Lease Payments S -i49 SZ-Q 9 27 4 k3-6~~Z~ AEP AEGCo APCo CSPCO 1814 KPCo OPCo (in thousands) Noncancellable operating Leases 2003 S 305,000 S 73,854 S 4,482 S 4,608 S 95,213 $ 1,031 S 62,784 2004 271,000 73,854 3,723 5,111 81,246 865 62,837 2005 252,000 73,854 3,114 4,013 78,968 747 62,169 2006 242,000 73,854 2,742 1,630 77,741 576 62,481 2007 237,000 73,854 1,962 1,374 76,461 875 62,880 Later Years 2 .462.000 1.107.810 4.384 2.670 1.117.725 1,492 180.548 Total Future Minimum Lease Payments SAC,769,0 I1 ,477,08 S2,0 1940-6S1,5Z7,3-54 LSLS,586 ,SA93,M9 PSO SWEPCo TCC TNC (in thousands) Noncancellable Operating Leases 2003 $ 2,260 S 912 $ 1,815 S 448 2004 1,998 617 1,565 296 2005 1,714 433 1,388 192 2006 1,391 317 1,086 169 2007 1,256 301 603 167 Later Years _ Total Future Minimum Lease Payments 5__ S 2,580 645 L-88
OPCo has entered into an agreement with JMG debt from a syndicate of banks and securities in a Funding LLP (JMG) an unrelated unconsolidated private placement to certain institutional investors. special purpose entity. JMG has a capital structure of which 3%is equity from investors with The gain from the sale was deferred and is being no relationship to AEP or any of its subsidiaries amortized over the term of the lease, which and 97% is debt from pollution control bonds and expires in 2022. The Owner Trustee owns the other bonds. JMG was formed to design, plant and leases it to AEGCo and l&M. The lease construct and lease the Gavin Scrubber for the is accounted for as an operating lease with the Gavin Plant to OPCo. JMG owns the Gavin payment obligations included in the lease Scrubber and leases it to OPCo. The lease is footnote. The lease term is for 33 years with accounted for as an operating lease with the potential renewal options. At the end of the lease payment obligations included in the lease term, AEGCo and l&M have the option to renew footnote. Payments under the operating lease are based on JMG s cost of financing (both debt the lease or the Owner Trustee can sell the plant. and equity) and include an amortization AEGCo, l&M nor AEP has ownership interest in component plus the cost of administration. the Owner Trustee and do not guarantee its debt. Neither OPCo nor AEP has an ownership interest in JMG and does not guarantee JMG s debt. 23. Lines of Credit and Sale of Receivables: At any time during the lease, OPCo has the option Lines of Credit AEP System to purchase the Gavin Scrubberforthe greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of The AEP System uses short-term debt, primarily JMG) or sell the Gavin Scrubber. The initial 15- commercial paper and revolving creditfacilities, to year lease term is non-cancelable. At the end of meet fluctuations in working capital requirements the initial term, OPCo can renew the lease, and other interim capital needs. AEP has purchase the Gavin Scrubber (terms previously established a utility money pool and a non-utility mentioned), or sell the Gavin Scrubber. In case money pool to coordinate short-term borrowings of a sale at less than the adjusted acquisition for certain subsidiaries. Utility money participants cost, OPCo must pay the difference to JMG. include AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. AEP also The use of JMG allows AEP to enter into an incurs borrowings outside of the money pool for operating lease while keeping the tax benefits other subsidiaries. As of December 31, 2002, otherwise associated with a capital lease. As of AEP had revolving credit facilities totaling $3.5 December 31, 2002, unless the structure of this billion to support its commercial paper program. arrangement is changed, it is reasonably possible At December 31, 2002, AEP had $3.2 billion that AEP will consolidate JMG in the third quarter outstanding in short-term borrowings of which of 2003 as a result of the issuance of FIN 46. $1.4 billion was commercial paper supported by Upon consolidation, AEP would record the assets, the revolving credit facilities. The maximum liabilities, depreciation expense, minority interest amount of commercial paper outstanding during and debt interest expense of JMG. AEP would the year, which had a weighted average interest eliminate operating lease expense. AEP s rate during 2002 of 2.47%, was $3.3 billion during maximum exposure to loss as a result of its April 2002. On December 11, 2002, Moodys involvement with JMG is approximately $560 Investor Services placed AEP s Prime-2 short-million of outstanding debt and equity of JMG as term rating for commercial paper under review for of December 31, 2002. possible downgrade. On January 24, 2003, Standard & Poor s Rating Services placed AEP s AEGCo and l&M entered into a sale and A-2 short-term rating for commercial paper under leaseback transaction in 1989 with Wilmington review for possible downgrade. On February 10, Trust Company (Owner Trustee) an unrelated 2003, Moodys Investor Services downgraded unconsolidated trustee for Rockport Plant Unit 2 AEP s short-term rating for commercial paper to (the plant). Owner Trustee was capitalized with Prime-3 from Prime-2. As a result, AEP s access equity from six owner participants with no to the commercial papermarketwill be limited and relationship to AEP or any of its subsidiaries and AEP will use other sources of funds as necessary. L-89
The registrant subsidiaries incurred interest transaction was entered into to allow AEP credit expense for amounts borrowed from the AEP to repay its outstanding debt obligations, continue money pool as follows: to purchase the AEP operating companies Year Ended December 31. receivables, and accelerate its cash collections. 2002 2001 2000 (in millions) AEGCO $0.4 5 0.8 $ - At December 31, 2002, the sale of receivables APCO 4.9 9.8 - agreement provided the banks and commercial CSPCo 3.2 5.0 1.4 I&M 0.4 13.1 0.8 paper conduits would purchase a maximum of KPCO OPCo 1.8 6.9 2.3 14.6 9.2
$600 million of receivables from AEP Credit, of PSO 5.4 6.3 7.5 which $454 million was outstanding. As SWEPCo 4.6 3.4 4.2 collections from receivables sold occur and are TCC 11.1 11.4 16.9 TNC 3.8 3.1 2.7 remitted, the outstanding balance for sold receivables is reduced and as new receivables Interest income earned from amounts advanced are sold, the outstanding balance of sold to the AEP money pool by the registrant receivables increases. All of the receivables sold subsidiaries were: represented affiliate receivables. The Year Ended December 31. commitments new term under the sale of 2002 2001 2000 (in millions) receivables agreement will remain at $600 million AEGCO $0.1 $ - S - until May 28, 2003. AEP Credit maintains a APCO 2.0 1.7 CSPCo 1.3 0.8 1.1 retained interest in the receivables sold and this I&M 2.0 1.6 9.0 KPCO - 0.1 1.8 interest is pledged as collateral for the collection OPco 0.8 8.6 3.4 of the receivables sold. The fair value of the PSO 1.1 -
SWEPCo 1.6 0.1 retained interest is based on book value due to TCC 2.0 0.1 the short-term nature of the accounts receivables less an allowance for anticipated uncollectible Outstanding short-term debt for AEP accounts. Consolidated consisted of: December 31. AEP Credit purchases accounts receivable 2002 2001 through purchase agreements with affiliated (in millions) Balance outstanding: companies and, until the first quarter of 2002, with Notes Payable $1,747 $1,063 non-affiliated companies. As a result of the commercial paper 1.417 2.948 Total $4.011 restructuring of electric utilities in the State of Sale of Receivables AEP Credit Texas, the purchase agreement between AEP Credit and Reliant Energy, Incorporated was AEP Credit entered into a sale of receivables terminated as of January 25, 2002 and the purchase agreement between AEP Credit and agreement with a group of banks and commercial paper conduits. Under the sale of receivables Texas-New Mexico Power Company, the last agreement, which expires May 28, 2003, AEP remaining non-affiliated company, was terminated Credit sells an interest in the receivables it on February 7, 2002. In addition, the purchase acquires to the commercial paper conduits and agreements between AEP Credit and its Texas banks and receives cash. This transaction affiliates AEP Texas Central Company (formerly constitutes a sale of receivables in accordance Central Power and Light Company) and AEP Texas North Company (formerly West Texas with SFAS 140 allowing the receivables to be taken off of AEP Credits balance sheet and Utilities Company) were terminated effective allowing AEP Credit to repay any debt obligations. March 20, 2002. AEP has no ownership interest in the commercial paper conduits and does not consolidate these entities in accordance with GAAP. We continue to service the receivables. This off-balance sheet L-90
Comparative accounts receivable information for AEP Credit: Year Ended December 31, 2002 2001 (in millions) Proceeds from sale of Accounts Receivable $5,513 $1,134 Accounts Receivable Retained Interest Less uncollectible Accounts and Amounts Pledged as Collateral 76 143 Deferred Revenue from Servicing Accounts Receivable 1 5 Loss on sale of Accounts Receivable 4 8 Average variable Discount Rate 1.92% 2.28% Retained Interest if 10% Adverse change in uncollectible Accounts 74 142 Retained Interest if 20% Adverse change in Uncollectible Accounts 72 140 Historical loss and delinquency amount for the AEP System s customer accounts receivable managed portfolio: Face value Year Ended December 31, 2002 2001 (in millions) Customer Accounts Receivable Retained S 466 S 343 Miscellaneous Accounts Receivable Retained 1,394 1,365 Allowance for uncollectible Accounts Retained (119) I6) Total Net Balance sheet Accounts Receivable 1,741 1,639 Customer Accounts Receivable securitized (Affiliate) 454 560 Customer Accounts Receivable securitized (Non-Affiliate) 485 Total Accounts Receivable managed 4-Net Uncollectible Accounts written off 48 72 L-91
Customer accounts receivable retained and The fees paid bythe registrant subsidiaries to securitized for the domestic electric operating AEP Credit for factoring customer accounts companies are managed by AEP Credit. receivable were: Miscellaneous account receivable have been Year Ended December 31. fully retained and not securitized. 2002 2001 2000 (in millions) At December 31, 2002, delinquent customer APCo S 4.8 15.8 S 5.2 15.2 S - 10.8 csPco accounts receivable was $30 million. I&NI 7.4 8.5 6.8 KPCO 2.7 2.7 1.9 OPCo 11.4 12.8 8.4 Under the factoring arrangement certain of PSO 7.2 9.6 8.3 the registrant subsidiaries (excluding AEGCo) SWEPCo 5.4 7.4 9.2 TCC 2.2 14.7 15.7 sell without recourse certain of their customer TNC 1.4 3.8 4.0 accounts receivable and accrued utility revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company s receivables and administrative costs. The costs of factoring customer accounts receivable is reported as an operating expense. The amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows: December 31_ 2002 2001 company (in millions) APCO S 67.6 S 61.2 CSPCo 114.3 105.7 I&M 103.7 94.9 KPCO 29.5 26.2 OPCo 109.8 100.2 PSO 83.7 70.7 SWEPCo 65.2 81.6 TCC - 145.3 TNC - 35.5 L-92
- 24. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows: 2002 Quarterly Periods Ended March 31 June 30 Sept. 30 Dec. 31 (In Millions - Except Per share Amounts) Revenues $3,169 $3,575 $3,870 $3,941 operating Income (Loss) 459 427 782 (405) Income (Loss) Before Discontinued operations, Extraordinary Items and cumulative Effect 159 158 386 (682) Net Income (Loss) (169) 62 425 (837) Earnings (Loss) per Share Before Discontinued operations, Extraordi nary Items and cumulative Effect* 0.49 0.49 1.14 (2.01) Earnings (Loss) per share** (0.53) 0.19 1.25 (2.47) 2001 Quarterlv Periods Ended March 31 June 30 Sept. 30 Dec. 31 (In Millions - Except Per share Amounts) Revenues $2,910 $3,259 $3,733 $2,865 operating Income 521 622 824 215 Income Before Discontinued operations, Extraordi nary Items and cumulative Effect 230 251 399 37 Net Income 266 232 421 52 Earnings per share Before Discontinued operations, Extraordinary Items and cumulative Effect*** 0.72 0.77 1.23 0.12 Earnings per share**** 0.83 0.72 1.31 0.16
- Amounts for 2002 do not add to $0.06 earnings per share before Discontinued Operations, Extraordinary Items and Cumulative Effect due to rounding and the dilutive effect of shares issued in 2002.
- Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.
- Amounts for 2001 do not add to $2.85 earnings per share before Discontinued Operations, Extraordinary Items and Cumulative Effect due to rounding.
- Amounts for 2001 do not add to $3.01 earnings per share due to rounding.
- Amounts for 2001 do not add to $2.85 earnings per share before Discontinued Operations, Extraordinary Items and Cumulative Effect due to rounding.
- Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.
The unaudited quarterly financial information for each AEP registrant subsidiary follows: L-93
Quarterly Periods Ended AEGCo APCO CSPCo I&M KPCo (in thousands) 2002 March 31 operating Revenues $49,875 $462,605 $314,826 $352,235 $ 99,185 Operating Income 1,767 81, 554 45,548 30,363 15,484 Income Before Extraordinary Items 1,893 55,341 33,858 11, 058 10,246 Net Income 1,893 55,341 33,858 11,058 10,246 June 30 operating Revenues $53,356 $432,015 $343,813 $369,043 S 92,164 operating Income 1, 504 65, 224 58,040 19,865 9,550 Income Before Extraordinary Items 1,718 46,608 51,721 7,494 5,246 Net Income 1,718 46,608 51,721 7,494 5,246 September 30 operating Revenues $55,988 $474,282 $428,437 $421,472 $100, 359 operating Income 1,436 81,365 89,033 57,004 11,119 Income Before Extraordinary Items 1,947 53,947 76,117 35,312 5,994 Net Income 1,947 53,947 76,117 35, 312 5,994 December 31 operating Revenues $54,062 $445,568 $313,084 $384,014 $ 86,975 operating Income 1,422 73,920 27,158 43,957 6,044 Income (LOSS) Before Extraordinary Items 1,994 49,596 19,477 20,128 (919) Net Income (Loss) 1,994 49,596 19,477 20,128 (919) Quarterly Periods Ended oPCo PSO SWEPCo TCC TNC (in thousands) 2002 March 31 operating Revenues $520,652 $148,986 $222,259 $278,910 $103,626 operating Income 83,716 8,410 22,469 55,445 11,145 Income (Loss) Before Extraordinary Items 64,051 (1 648) 8,159 24,445 3,992 Net Income (LOSS) 64,051 (1,648) 8,159 24,445 3,992 June 30 operating Revenues $521,365 $158,330 S263,074 $360,391 S104,452 operating Income 61,046 20,201 31, 988 64,319 5,547 Income Before Extraordinary Items 55,348 11,620 18,155 33, 535 675 Net Income 55,348 11,620 18,155 33,535 675 september 30 operating Revenues $566,366 S230,098 $362,423 S546,260 $152,667 operating Income (LOSS) 97,210 50,710 60,254 118,204 (308) Income (LOSS) Before Extraordinary Items 80,258 41,002 45,794 93, 383 (4,193) Net Income (LOSS) 80,258 41,002 45,794 93, 383 (4,193) December 31 operating Revenues $504,742 $256,233 $236,964 $504,932 S 89,995 operating Income (LOSS) 56,357 5,400 27,758 155, 765 (8,513) Income (LOSS) Before Extraordinary Items 20,366 (9,914) 10,884 124,578 (14,151) Net Income (LOSS) 20,366 (9,914) 10,884 124,578 (14,151) Quarterlv Periods Ended AEGCo APCo cSPCo I&M KPCo (in thousands) 2001 March 31 operating Revenues $60, 507 $501,204 $327,437 $387,813 $100,681 operating Income 1,807 88,152 51,932 52, 698 12,604 Income Before Extaordinary Items 1,980 61,787 37,671 32, 363 7,075 Net Income 1,980 61,787 37,671 32,363 7,075 June 30 operating Revenues $52,217 $430,412 $333,995 $382,234 S 89,541 operating Income 1,882 59,362 62,894 47,340 8,364 Income Before Extrodinary Items 2,063 36,419 47,418 27,374 2,742 Net Income 2,063 36,419 21,011 27, 374 2,742 seotember 30 operating Revenues $57,417 S434,450 $375,691 $398,457 $ 96,197 operating Income 1,615 60,381 76,920 44,509 12,587 Income Before Extraordinary Items 2,051 30,317 65,318 25,064 5,312 Net Income 2,051 30,317 65, 318 25,064 5,312 December 31 operating Revenues $57,407 $418,193 $313,196 $358,493 S 92,606 operating Income 1,673 67,091 60,431 15, 158 14,123 Income (LOSS) Before Extraordinary Items 1,781 33,295 41,493 (9,013) 6,436 Net Income (LOSS) 1,781 33,295 37,876 (9,013) 6,436 L-94
Quarterly Periods Ended oPco PSO SWEPCo TCC TNC (in thousands) 2001 March 31 operating Revenues $552,503 $225,080 $267,117 S432,910 $141,649 operating Income 64,756 8,340 33,986 64,152 5,392 Income (Loss) Before Extraordinary Items 53,397 (1,560) 19,869 35,031 891 Net Income (Loss) 53,397 (1,560) 19,869 35,031 891 June 30 operating Revenues $512,196 S265,360 S271,748 $470,420 S139,228 operating Income 47,067 21,942 32,649 82,351 12,428 Income Before Extraordinary Items 32,094 11,921 17,784 52,518 6,133 Net Income 10,579 11,921 17,784 52,518 6,133 seDtember 30 operating Revenues $535,535 S325,373 S331,441 S527,117 S181,433 operating Income 69,668 59,914 60,194 112,598 17,745 Income Before Extraordinary Items 51,378 51,069 46,357 83,702 14,067 Net Income 51,378 51,069 46,357 83,702 14,067 December 31 operating Revenues $497,871 $141,187 $231,020 $308,390 S 94,148 operating Income (Loss) 59,219 6,792 19,378 36,630 (2,175) Income (Loss) Before Extraordinary Items 28,924 (3,671) 5,357 13,536 (8,781) Net Income (Loss) 32,091 (3,671) 5,357 11,027 (8,781) Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect for the fourth quarter 2002 decreased $896 million from the prior year due to the impairment loss and impairment value losses of approximately $1,188 million (pre-tax) to reduce the valuation of under-performing assets. In addition to the impairments that were recorded during the fourth quarter, a change in AEP s Accumulated Other Comprehensive Income (Loss) of $585 million for pension liability had a negative effect on each registrant s Consolidated Balance Sheets.
- 25. Trust Preferred Securities:
The following Trust Preferred Securities issued by the Wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding at December31,2002 and December 31,2001. They are classified on AEP s, PSO s, SWEPCo s and TCC s Balance Sheets as Certain Subsidiary Obligated, Mandatorily Redeemable Preferred Securities of SubsidiaryTrusts Holding SolelyJunior Subordinated Debentures of Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. TCC reacquired 490,000 trust preferred units during 2001. Units Issued/ Description of outstanding underlying Business Trust SecuritY At 12/31/02 Amount at December 31. Debentures of Registrant 2002 2001 (in millions) CPL Capital I 8.00%, Series A 5,450,000 $136 $136 TCC, S141 million, 8.00%, series A Pso capital I 8.00%, series A 3,000,000 75 75 PSO, $77 million, 8.00%, Series A SWEPCO Capital I 7.875%, series A 4.400.000 110 110 SWEPCO, S113 million, 7.875%, Series A 12W~iDSOOQ 311 1321 Each of the business trusts is treated as a subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.
- 26. Minority Interest in Finance Subsidiary:
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was L-95
capitalized with the assets of Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that is convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne and $750 million from Steelhead Investors LLC ("Steelhead - non-controlling preferred member interest). As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and has a capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company. Underthe provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (4.784% and 4.413% for the quarters ended December 31,2002 and 2001, respectively). Caddis has the right to redeem Steelhead s interest at any time. The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006, and is supported by the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne s $321.4 million of preferred stock inAEP Gas Holding. The preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP s stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if SubOne were to reduce its loan with Caddis by $225 million. The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2002, we have complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries debt outstanding in excess of $50 million isan event of default under the credit agreement. The initial period of Steelhead s investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead s return rate, re-market Steelhead s interests to new investors, redeem Steelhead s interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements. Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events including a default inthe payment of the preferred return, Steelhead s rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the AEP Gas Holding preferred stock into AEP common stock. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP s liquidity. Caddis and SubOne are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and SubOne are consolidated with AEP for financial reporting purposes. Steelhead s investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP s consolidated statements of operation and consolidated balance sheets as Minority Interest in Finance Subsidiary. AEP s maximum exposure to loss as a result of its involvement with Steelhead is $321.4 million of preferred stock, $83million underthe subscription agreementto Caddisforanylossesincurred by Caddis and the cash reserve fund balance of $34 million (as of December 31,2002) due Caddis for L-96
default under the intercompany loan agreement. AEP can reduce its maximum exposure related to the preferred stock by a reduction of $225 million of the intercompany loan. As of December 31, 2002, we are continuing to review the application of FIN 46 as it relates to the Steelhead transaction.
- 27. Equity Units In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consists of a forward purchase contract and a senior note.
The forward purchase contracts obligate the holders to purchase shares of AEP common stock on August 16,2005. The purchase price perequityunit is $50. The numberof sharesto be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. Holders may satisfy their obligation to purchase AEP common stock under the forward purchase contracts by allowing the senior notes to be remarketed or by continuing to hold the senior notes and using other resources as consideration for the purchase of stock. If the holders elect to allow the notes to be remarketed, the proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that the holders will pledge to AEP in order to meet their obligations under the forward purchase contracts. The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are the collateral that secures the holders requirement to purchase common stock under the forward purchase contracts. AEP will make quarterly interest payments on the senior notes at the initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP will make contract adjustment payments to the purchaser at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments has been recorded as a $31 million liability in Equity Unit Senior Notes offset by a charge to Paid-in Capital. Interest payments on the senior notes are reported as interest expense. Accretion of the contract adjustment payment liability is reported as interest expense. AEP applies the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contract are used to repurchase outstanding shares. L-97
- 28. Jointly Owned Electric Utility Plant:
CSPCo, PSO, SWEPCo, TCC and TNC have generating units that are jointly owned with unaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each AEP registrant subsidiary s proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments are reflected in its balance sheets under utility plant as follows: company's share December 31. 2UUz zUU1 Percent utility Construction utility Construction of Plant work Plant work ownership in service in Progress in Service in Progress (in thousands) (in thousand s) CSPCo: W.C. Beckjord Generating Station (Unit No. 6) 12.5 S 15,487 S 49 $ 14,292 S 884 conesville Generating Station (Unit No. 4) 43. 5 81,960 279 81,697 494 J.M. Stuart Generating station 26.0 197,276 44,865 193,760 27,758 wm. H. Zimmer Generating Station 25.4 705,620 14,077 704,951 2,634 Transmission (a) 61.187 2.281 61.476 91 S1,06,130 51, 056,17 PSO: oklaunion Generating station (Unit No. 1) 15.6 5___233Jfi2 3 77 5==BZJA S--634 SWEPCo: Dolet Hills Generating Station (Unit NO. 1) 40.2 S 235,366 1,313 S 234,747 S 675 Flint creek Generating Station (Unit No. 1) 50.0 91,567 1,052 83,953 213 Pirkey Generating Station (Unit NO. 1) 85.9 451.136 2.197 439,430 10 577 S 778069 S4,562 TCC: oklaunion Generating station (Unit No. 1) 7.8 S 38,055 S 369 S 37,728 S 318 South Texas Project Generating Station (Units No. 1 and 2) 25.2 2.364.359 43.887 2.360.452 41.571 52,402,414 4,5 S-2,3-818 S41,889 TNC: oklaunion Generating station (Unit No. 1) 54.7 LT~~~~ (a) varying percentages of ownership. The accumulated depreciation with respectto APCo, CSPCo, I&M, KPCo and OPCo are each AEP registrant subsidiarys share of parties to the Interconnection Agreement, jointly owned facilities is shown below: dated July 6, 1951, as amended (the Interconnection Agreement), defining how December 31, they share the costs and benefits associated 2002 2001 with their generating plants. This sharing is (in thousands) CSPCo $436,683 $410,756 based upon each company s "member-load-Pso 49,085 35,653 ratio, which is calculated monthly on the SWEPCo 450,057 392,728 basis of each companys maximum peak TCC 927,193 863,130 demand in relation to the sum of the TNC 102,542 100,430 maximum peak demands of all five companies during the preceeding 12 months.
- 29. Related Party Transactions In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Power Pool AEP System Interim Allowance Agreement which provides, among other things, for the L-98
transfer of S02 Allowances associated with dated as of January 1, 1997 (CSW Operating transactions under the Interconnection Agreement). The CSW Operating Agreement Agreement. As part of AEP s restructuring requires the operating companies of the west settlement agreement filed with FERC, under zone to maintain specified annual planning certain conditions CSPCo and OPCo would reserve margins and requires the operating no longer be parties to the Interconnection companies that have capacity in excess of the Agreement and certain other modifications to required margins to make such capacity its terms would also be made. available for sale to other operating companies as capacity commitments. The Power marketing and trading transactions CSW Operating Agreement also delegates to (trading activities) are conducted by the AEP AEP Service Corporation the authority to Power Pool and shared among the parties coordinate the acquisition, disposition, under the Interconnection Agreement. planning, design and construction of Trading activities involve the purchase and generating units and to supervise the sale of electricity under physical forward operation and maintenance of a central contracts at fixed and variable prices and the control center. As part of AEP s restructuring trading of electricity contracts including settlement agreement filed with the FERC, exchange traded futures and options and under certain conditions TCC and TNC would over-the-counter options and swaps. The no longer be parties to the CSW Operating majority of these transactions represent Agreement. physical forward contracts in the AEP System s traditional marketing area and are AEP s System Integration Agreement typically settled by entering into offsetting provides for the integration and coordination contracts. of AEP s east and west zone operating subsidiaries, joint dispatch of generation In addition, the AEP Power Pool enters into within the AEP System, and the distribution, transactions for the purchase and sale of between the two operating zones, of costs electricity options, futures and swaps, and for and benefits associated with the System s the forward purchase and sale of electricity generating plants. It is designed to function outside of the AEP System s traditional as an umbrella agreement in addition to the marketing area. AEP Interconnection Agreement and the CSW Operating Agreement, each of which PSO, SWEPCo, TCC, TNC and AEP Service will continue to control the distribution of costs Corporation are parties to a Restated and and benefits within each zone. Amended Operating Agreement originally L-99
The following table shows the revenues derived from sales to the Pools and direct sales to affiliates for years ended December 31, 2002, 2001 and 2000: APCo CSPCo I&M KPCo OPCo AEGCo Related Party Revenues (in thousands) 2002 sales to East system Pool $106,651 $42,986 S 197,525 S 22,369 $397,248 S - Sales to west System Pool 18,300 12,107 13,036 4,717 16,265 - Direct Sales To East Affiliates 58,213 - - - 50,599 213,071 Direct sales To West Affiliates - - other 3 313 2.109 3 577 878 1.090 - Total Revenues S=f 21,3 S 27,96 SAELM2S23,7 2001 sales to East System Pool $ 91,977 $44,185 S 239,277 S 34,735 $431,637 $ - Sales to West System Pool 24,892 13,971 15,596 6,117 19,797 - Direct sales To East Affiliates 54,777 - - - 55,450 227,338 Direct sales To West Affiliates (3,133) (1,705) (1,905) (744) (2,590) - other 2.772 11.060 2.071 2 258 7.072 - Total Revenues S171,285 $ 2550,74 2000 sales to East System Pool S 81,013 $36,884 S 200,474 S 36,554 $502,140 S - sales to west system Pool 7,697 4,095 4,614 1,829 6,356 - Direct Sales To East Affiliates 59,106 - 66,487 227,983 Direct sales To West Affiliates 4,092 2,262 2,510 972 3,421 - other 2,770 6.124 2.466 4.043 - S 271038 Total Revenues ST41NC 244Z S PSO SWEPCo TCC TNC Related Party Revenues (in thousands) 2002 Sales to East System Pool 5- - $ - 5-sales to West System Pool 674 1,334 18,416 1,280 Direct sales To East Affiliates 611 270 366 (23) Direct sales To West Affiliates 6,047 75,674 956,751 228,404 other 2,107 (4.979) 32.911 10.764 Total Revenues I-9,439 57,9 1,008,44A 20,2 2001 Sales to East System Pool S 4S - $ - $ - sales to west System Pool 3,317 8,073 19,865 322 Direct sales To East Affiliates 2,833 3,238 3,697 1,228 Direct Sales To West Affiliates 30,668 67,930 12,617 9,350 Other (51) (4) 5.583 7.1781 Total Revenues 2000 Sales to East System Pool S- S- S - S - Sales to West System Pool 7,323 5,546 23,421 194 Direct sales To East Affiliates (1,990) (3,008) (3,348) (1,116) Direct Sales TO West Affiliates 21,995 62,178 12,516 7,645 other (12.680) (1.592) 5,163 11.931 Total Revenues The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2002, 2001, and 2000: APCo CSPCo I&M KPCo OPCO Related Party Purchases (in thousands) 2002 Purchases from East System Pool $233,677 $309,999 $ 83,918 S 68,846 S70,338 Purchases from West System Pool 337 219 237 86 297 Direct Purchases from East Affiliates 583 387 149,569 64,070 519 Direct Purchases from West Affiliates Total Purchases S234,59 S310,605 S71,154 2001 Purchases from East System Pool $346,582 $292,034 S 79,030 S 61,816 $62, 350 Purchases from West System Pool 296 165 185 72 235 Direct Purchases from East Affiliates - - 159,022 68,316 Direct Purchases from west Affiliates Total Purchases S346i 5292,~R199 SL238,237 5130,20A 2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 S50,339 Purchases from west System Pool 455 260 285 108 390 Direct Purchases from East Affiliates - - 158,537 69,446 Direct Purchases from west Affiliates 14 8 9 3 12 Total Purchases 53-LM SZL105214 L-1 00
PSO SWEPCo TCC TNC Related Party Purchases (in thousands) 2002 Purchases from East System Pool S 343 S - S - S - Purchases from West system Pool 874 (456) 1,366 15,475 Direct Purchases from East Affiliates 29,029 17,242 8.236 2,669 Direct Purchases from West Affiliates 59.208 25 236 13.804 19 438 Total Purchases M-,06S758 2001 Purchases from East System Pool S 1,327 S - S - $ 4 Purchases from West System Pool 5,877 3,810 415 11,689 Direct Purchases from East Affiliates 1,951 2,352 12.657 4,614 Direct Purchases from west Affiliates 34,603 9.696 45 569 40,349 Total Purchases 2000 Purchases from East System Pool S20,100 S - S - S - Purchases from west System Pool 5,386 4,379 1,696 18,444 Direct Purchases from East Affiliates 2,117 695 251 71 Direct Purchases from west Affiliates 33 185 8 264 30 644 39 258 Total Purchases The above summarized related party revenues and expenses are reported in their entirety, without elimination, and are presented as operating revenues affiliated and purchased power affiliated on the statements of operations of each AEP Power Pool member. Since all of the above pool members are included in AEP s consolidated results, the above summarized related party transactions are eliminated in total in AEP s consolidated revenues and expenses. L-101
AEP System Transmission Pool Transmission Agreement during the years ended December 31, 2002, 2001 and 2000: APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated 2002 2001 2000 (in thousands) April 1, 1984, as amended (the Transmission PSO S(4,200) S (4,000) S (3,300) Agreement), defining how they share the SWEPCo (5,000) (5,400) (5,900) costs associated with their relative ownership TCC 3,600 3,900 3,400 TNC 5,600 5, 500 5,800 of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain AEP s System Transmission Integration facilities operated at lower voltages (138 kv Agreement provides for the integration and and above). Like the Interconnection coordination of the planning, operation and Agreement, this sharing is based upon each maintenance of the transmission facilities of company s "member-load-ratio. AEP s east and west zone operating subsidiaries. Like the System Integration The following table shows the net (credits) or Agreement, the System Transmission charges allocated among the parties to the Integration Agreement functions as an Transmission Agreement during the years umbrella agreement in addition to the AEP ended December 31, 2002, 2001 and 2000: Transmission Agreement and the 2002 2001 2000 Transmission Coordination Agreement. The (in thousands) System Transmission Integration Agreement APCo S (13,400) S (3,100) $ (3,400) contains two service schedules that govern: CsPCO 42,200 40,200 38,300 I&M (36,100) (41,300) (43,800) KPCo (5,400) (4,600) (6,000)
- The allocation of transmission costs and OPCO 12,700 8,800 14,900 revenues.
- The allocation of third-party transmission PSO, SWEPCo, TCC, TNC and AEP Service costs and revenues and System dispatch Corporation are parties to a Transmission costs.
Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA established The Transmission Integration Agreement a coordinating committee, which is charged anticipates that additional service schedules with the responsibility of overseeing the may be added as circumstances warrant. coordinated planning of the transmission facilities of the west zone operating Unit PowerAgreements and Other subsidiaries, including the performance of transmission planning studies, the interaction A unit power agreement between AEGCo and of such subsidiaries with independent system l&M (the l&M Power Agreement) provides for operators (ISO) and other regional bodies the sale by AEGCo to l&M of all the power interested in transmission planning and (and the energy associated therewith) compliance with the terms of the Open available to AEGCo at the Rockport Plant Access Transmission Tariff (OATT) filed with unless it is sold to another utility. I&M is the FERC and the rules of the FERC relating obligated, whether or not power is available to such tariff. from AEGCo, to pay as a demand charge for the right to receive such power (and as an Under the TCA, the west zone operating energy charge for any associated energy subsidiaries have delegated to AEP Service taken by l&M) such amounts, as when added Corporation the responsibility of monitoring to amounts received by AEGCo from any the reliability of their transmission systems other sources, will be at least sufficient to and administering the OATT on their behalf. enable AEGCo to pay all its operating and The TCA also provides for the allocation other expenses, including a rate of return on among the west zone operating subsidiaries the common equity of AEGCo as approved by of revenues collected for transmission and FERC, currently 12.16%. The l&M Power ancillary services provided under the OATT. Agreement will continue in effect until the expiration of the lease term of Unit 2 of the The following table shows the net (credits) or Rockport Plant unless extended in specified charges allocated among the parties to the circumstances. L-1 02
Pursuant to an assignment between l&M and American Electric Power Service Corporation KPCo, and a unit power agreement between (AEPSC) provides certain managerial and KPCo and AEGCo, AEGCo sells KPCo 30% professional services to AEP System of the power (and the energy associated companies. The costs of the services are therewith) available to AEGCo from both units billed to its affiliated companies byAEPSC on of the Rockport Plant. KPCo has agreed to a direct-charge basis, whenever possible, and pay to AEGCo in consideration for the right to on reasonable bases of proration for shared receive such power the same amounts which services. The billings for services are made I&M would have paid AEGCo under the terms at cost and include no compensation for the of the l&M Power Agreement for such use of equity capital, which is furnished to entitlement. The KPCo unit power agreement AEPSC byAEP Co., Inc. Billings from AEPSC expires on December 31, 2004. This unit are capitalized or expensed depending on the power agreement extends until December 31, nature of the services rendered. AEPSC and 2009 for Unit 1 and until December 7, 2022 its billings are subject to the regulation of the for Unit 2 if AEP s restructuring settlement SEC under the PUHCA. agreement filed with the FERC becomes operative. 30. Subsequent Events (Unaudited): APCo and OPCo, jointly own two power Common Stock Offering On February 27, plants. The costs of operating these facilities 2003, AEP priced its offering of 50 million are apportioned between the owners based shares of common stock at a public offering on ownership interests. Each companys price of $20.95 per share. AEP has granted share of these costs is included in the the underwriters an option to purchase an appropriate expense accounts on each additional 7.5 million shares of common stock company s consolidated statements of to cover overallotments. The net proceeds income. Each company s investment in these from the sale of these securities will be used plants is included in electric utility plant on its to reduce debt and for general corporate consolidated balance sheets. purposes. I&M provides barging services to AEGCo, SeniorNotes Offering During March 2003, APCo and OPCo. I&M records revenues from AEP completed an offering of 5.375% Series barging services as nonoperating income. C Senior Notes which have a principal AEGCo, APCo and OPCo record costs paid amount of $500 million and a maturity date of to l&M for barging services as fuel expense. March 15, 2010. The net proceeds from the The amount of affiliated revenues and offering will be used to repay or redeem affiliated expenses were: current maturities of long-term debt, a portion of our minority interest in a financing Year Ended December 31. 2002 2001 2000 subsidiary, and for general corporate company (in millions) purposes. I&M revenues $34.3 $30.2 $23.5 AEGCo expense 7.8 8.5 8.8 APCo expense 12.8 11.5 7.8 OPCo expense 7.9 10.2 6.9 Memco expense 5.7 AEP Energy services 0.1 L-103
REGISTRANTS COMBINED MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION. ACCOUNTING POLICIES AND OTHER MATTERS The following is a combined presentation of credit reviews of AEP and its registrant management s discussion and analysis of subsidiaries. The agencies are also reviewing financial condition, accounting policies and most companies in the energy sector due to other matters for AEP and its registrant issues which impact the entire industry, not subsidiaries. Management s discussion and only AEP and its subsidiaries. analysis of results of operations for AEP and each of its subsidiary registrants is presented In February 2003, Moody s Investors Service with their financial statements earlier in this (Moody s) completed their review of AEP and document. The following is a list of sections its rated subsidiaries. The results of that of managements discussion and analysis of review were downgrades of the following financial condition, accounting policies and ratings for unsecured debt: AEP to Baa3 from other matters and the registrant to which they Baa2, APCo from Baal to Baa2, TCC from apply: Baal to Baa2, PSO from A2 to Baal, SWEPCo from A2 to Baal. TNC, which had Financial condition AEP, AEGCo, APCo, CSPCo, I&M, KPCo, no senior unsecured notes outstanding at the OPco, Pso, time of the ratings action, had its mortgage SWEPCo, TCC, TNC bond debt downgraded from A2 to A3. AEP s critical Accounting commercial paper was also concurrently Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, downgraded from P-2 to P-3. The completion OPCo, PSO, SWEPCo, TCC, TNC of this review was a culmination of earlier ratings action in 2002 that had included a Market Risks AEP, AEGCo, APCo, CSPCo, I&M, KPCo, downgrade of AEP from Baal to Baa2 and OPco, Pso, the placement of five of the registrant SWEPCo, TCC, TNC subsidiaries on negative outlook. With the industry Restructuring AEP, APCo, CSPCo completion of the reviews, Moody s has I&M, KPCO, OPCo, PSO, SWEPCo, TCC, placed AEP and its rated subsidiaries on TNC stable outlook. Litigation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPco, Pso, In February 2003, Standard & Poor s placed SWEPCo, TCC, TNC AEP s senior unsecured debt and commercial Environmental concerns paper ratings on credit watch with negative and Issues AEP, AEGCo, APCo, implications, and did the same with the CSPCo, I&M, KPCo OPCo, PSO, subsidiaries. S&P indicated that resolution SWEPCo, TCC, TNC regarding these actions would come within a other Matters AEP, AEGCo, APCo, short time (see additional discussion in CSPCo, I&M, KPCo, OPCo, Pso, Financing Credit Ratings in Item 1 of Part I). SWEPCo, TCC, TNC In 2002, Fitch Ratings Service downgraded Financial Condition both PSO and SWEPCo from A to A- for the senior unsecured notes. Fitch has AEP and We measure our financial condition by the its subsidiaries on stable outlook and the strength of the balance sheets and the commercial paper rating is stable at F-2 (see liquidity provided by cash flows and earnings. additional discussion in Financing Credit Ratings in Item 1 of Part I). Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality. Credit Ratings The rating agencies have been conducting M-1
Current ratings of AEP s subsidiaries' first Liquidity mortgage bonds are listed in the following table: Liquidity, or access to cash, has become a Company Moody s S&P Fi tch more critical factor in determining the financial stability of a company due to volatility in APCo Baal BBB+ A-CSPCo A3 BBB+ A wholesale power markets and the potential I&M Baal BBB4- BBB-i limitations that credit rating downgrades place. KPCo Baal B8BB- ABB+ OPCo A3 8BBB- A- on a company s ability to raise capital. PSO SWEPCO A3 A3 BBB+ BBB+i A A Management is committed to preserving an TCC Baal BB 8+ A adequate liquidity position and addressing TNC A3 BB B4 A AEP and its subsidiaries financial needs in 2003. Current short-term ratings are as follows: Company Moody s s&P Fitch As of December 31, 2002, we had an available liquidity position of $3.5 billion as AEP P-3 A-2 F-2 illustrated in the table below: The current ratings for senior unsecured debt Credit Facili;ties are listed in the following table: (in millions) Maturity Commercial Paper sackuF Company Moody s S&P Fi tch Lines of Credit S2,500* 5/03 commercial Paper Backul AEP Baa3 BBB+ BBB+ AEP Resources* Baa3 BBB+ Lines of Credit 1,000 5/05 BBB+ Corporate Separation APCo Baa2 BBB+ BBB+ CSPCo A3 BBB+ A-Revolving credit 1,725 4/03 Euro Revolving credit I&M Baa2 BBB+ Be8 315 KPCo Baa2 BBB+ Be8 Facilities 10/03 OPCO A3 BBB+ BBB+ Total 5,540 PSO Baal BBB* A- cash SWEPCO Baal BBB+ A-TCC Baa2 BBB+ A-Liquidity Reserve 1.000** Total credit Facilities TNC Baal BBB+ A- and Cash 6,540
- The rating is for a series of senior notes issued with a Support Agreement from AEP. Less: Commercial Paper Outstanding Corporate Separation 1,415 Loans 1,300 AEP's common equity to total capitalization Euro Revolving declined to 32% in 2002 from 36% in 2001 credit Loans 305 Total Available Liquidity 2Q and 37% in 2000. Total capitalization includes long-term debt due within one year,
- Contains one year term-out provision.
** unrestricted and excludes S213 million equity unit senior notes, minority interest and of operational cash on hand.
short-term debt. Preferred stock at 1% remained unchanged. In2002, long-term debt including equity unit senior notes and trust AEP and its subsidiaries goal for 2003 is to preferred securities increased from 43% to use cash from operations to fund capital 50% while Short-term Debt decreased from expenditures, dividend payments and working 17% to 14% and Minority Interest in Finance capital requirements. Short-term debt is used Subsidiary remained unchanged at 3%. In as an interim bridge for timing differences in 2001 Long-term Debt remained unchanged the need for cash or to fund debt maturities while Short-term Debt decreased from 20% to until permanent financing is arranged. 17% and Minority Interest in Finance Subsidiary increased to 3%. In 2002, 2001 Short-term funding comes from the parent and 2000, AEP did not issue any shares of company s commercial paper program and common stock to meet the requirements of revolving credit facilities. Proceeds are the Dividend Reinvestment and Direct Stock loaned to the subsidiaries through Purchase Plan and the Employee Savings intercompany notes. AEP and its subsidiaries Plan. Common stock was issued in 2002 for also operate a non-utility and utility money stock options exercised and under an equity pool to minimize the AEP System s extemal offering (discussed in Financing Activity). short-term funding requirements and sell accounts receivable to provide liquidity for the domestic electric subsidiaries. The M-2
commercial paper program isbacked by $3.5 unused and available at December 31, 2002. billion in bank facilities of which $1 billion matures in May 2005. The remaining $2.5 During 2002, cash flow from operations was billion matures in May 2003 and has a one- $1.7 billion, including $21 million from Net year term-out provision at AEP s option. At Income Before Discontinued Operations, December 31, 2002, approximately $1.4 Extraordinary Items and Cumulative Effect, billion of commercial paper was outstanding. approximately $1.3 billion from depreciation, A portion of the commercial paper balance is amortization, deferred taxes, and deferred related to funding of debt maturities of the investment tax credits, approximately $1.1 Ohio and Texas subsidiaries pending a billion associated with asset, investment value permanent financing program. The Ohio and and other impairments, offset by additional Texas subsidiaries issued $2,025 million of working capital requirements of approximately senior unsecured notes in February 2003 with $700 million. These additional working capital maturity dates ranging from 2005 to 2033. requirements reflect the one time impact of The commercial paper balance outstanding the discontinuance of the sale of accounts decreased in early 2003 due to repayment receivable for Texas companies and billing with proceeds from these issuances. delays related to the transition to customer choice in Texas, higher margin requirements AEP also has a $1.725 billion bank facility for gas trading, seasonal fuel inventory maturing in April 2003 that is available for growth, and other miscellaneous items. debt refinancing. At December31,2002, $1.3 Construction expenditures were $1.7 billion billion was outstanding under that facility. including major expenditures for emission With the issuance of the permanent financing control technology on several coal-fired for the Ohio and Texas subsidiaries generating units (see discussion in Note 9). mentioned above, this fajlity was repaid and Dividends on common stock were $793 cancelled in February 2003. million. Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the AEP also has -revolving credit facilities in Texas REPs and the issuance of common place for 300 million Euros to support the stock, common equity units, 15-year notes for wholesale business in Europe. At December a wind generation project and transition 31, 2002, the majority of these facilities were funding bonds provided funds to reduce debt, drawn. fund construction and pay dividends. AEP also maintains a minimum $300 million During 2001, AEP s cash flow from operations cash liquidity reserve fund to support its was $2.8 billion, including $885 million from marketing operations in the U.S. and keeps Net Income Before Discontinued Operations, additional cash on hand as market conditions Extraordinary Items and Cumulative Effect change. At December 31, 2002, AEP had $1 and $1.4 billion from depreciation, billion of cash available for liquidity. amortization, deferred taxes and deferred investment tax credits. Capital expenditures On December 6, 2002, we closed a 364-day, including acquisitions were $3.9 billion and $425 million facility and used it to partially dividends on common stock were $773 repay the maturing interim financing for the million. Cash from operations less dividends U.K. generation plants (FFF). The facilitywas on common stock financed 51% of capital secured by a pledge of the shares of AEP expenditures. companies in the FFF ownership chain and guaranteed bythe parent company. A portion During 2001, the proceeds of AEP s $1.25 ($213 million) of the facility is due in May billion global notes issuance and proceeds 2003. The remainder of the FFF interim from the sale of a U.K. distribution company financing was repaid using a combination of and two generating plants provided cash to existing funds and draws against the Euro purchase assets, fund construction, retire revolving credit facilities. debt and pay dividends. Major construction expenditures include amounts for a wind In total, we had approximately $6.5 billion in generating facility and emission control liquidity sources of which $3.5 billion were technology on several coal-fired generating M-3
units. Asset purchases include HPL, coal be immediately payable. mines, a barge line, a wind generating facility and two coal-fired generating plants in the FinancingActivity U.K. These acquisitions accounted for the increase in total debt during 2001. Long-term Common Stock funding arrangements for specific assets are often complex and typically not completed In June 2002, AEP issued 16 million shares until after the acquisition. of common stock at $40.90 per share through an equity offering and received net proceeds The loss for 2002 resulted in a negative of $634 million. Proceeds from the sale of dividend payout ratio of 153% reflecting the equity units and common stock were used to losses on sale and impairments of assets. pay down short-term debt and establish a Earnings for 2001 resulted in a dividend cash liquidity reserve fund. payout ratio of 80%, a considerable improvement over the 289% payout ratio in Equity Units 2000. The abnormally high ratio in 2000 was the result of the adverse impact on 2000 In June 2002, AEP issued 6.9 million equity earnings from the Cook Plant extended units at $50 per unit ($345 million). See Note outage and related restart expenditures, 27 for additional information. merger costs and the write-off related to COLI and non-regulated subsidiaries. Debt AEP and its subsidiaries generally use short- In February 2002, TCC issued $797 million of term borrowings to fund property acquisitions securitization notes that were approved bythe and construction until long-term funding PUCT as part of *Texas restructuring to mechanisms are arranged. Some recover generation related regulatory assets. acquisitions of existing business entities The proceeds were used to reduce TCC s include the assumption of their outstanding debt and equity. debt and certain liabilities. Sources of long-term funding include issuance of AEP In April 2002, AEP closed on a bridge loan common stock, minority interest or long-term facility consisting of a $1.125 million 364-day debt and sale-leaseback or leasing arrange- revolving credit facility and a $600 million 364-ments. The domestic electric subsidiaries day term loan facility to prepare for corporate generally issue short-term debt to provide for separation. At year-end, $600 million was interim financing of capital expenditures that borrowed under the term loan facility and exceed internally generated funds and $700 million was borrowed under the periodically reduce their outstanding short- revolving credit facility. Those amounts were term debt through issuances of long-term debt repaid and the facility terminated when bonds and additional capital contributions from their were issued by CSPCo, OPCo, TCC and TNC parent company. in February 2003. AEP s revolving credit agreements include In February 2003, CSPCo issued $250 covenants that require performance of certain million of unsecured senior notes due 2013 at actions, including maintaining specified a coupon of 5.50% and $250 million of financial ratios. Non-performance of these unsecured senior notes due 2033 at a coupon covenants may result in an event of default of 6.60%. OPCo issued $250 million of under these credit agreements. At December unsecured senior notes due 2013 at a coupon 31, 2002, AEP complied with the covenants of 5.50% and $250 million of unsecured contained in these credit agreements. In senior notes due 2033 at a coupon of 6.60%. addition, a default under any other agreement TCC issued $100 million of unsecured senior or instrument relating to debt outstanding in notes due 2005 at a variable rate, $150 excess of $50 million is an event of default million of unsecured senior notes due 2005 at under these credit agreements. An event of a coupon of 3.0%, $275 million of unsecured default under these credit agreements would senior notes due 2013 at a coupon of 5.50% cause all amounts outstanding thereunder to and $275 million of unsecured senior notes M-4
due 2033 at a coupon of 6.65%. TNC issued December 31, 2002, AEP had credit facilities
$225 million of unsecured senior notes due totaling $3.5 billion to support its commercial 2013 at a coupon of 5.50%. The use of paper program. At December 31, 2002, AEP proceeds from the above bonds was had $1.4 billion outstanding in short-term repayment of the bridge loan facility borrowings subject to these credit facilities.
mentioned above, repayment of short-term debt, and for general corporate purposes. AEP Credit purchases, without recourse, the accounts receivable of most of the domestic In 2002, the following issuances were utility operating companies. AEP Credits completed by the subsidiaries of AEP: financing for the purchase of receivables changed in December 2001. Starting December 31, 2001, AEP Credit entered into Pri n- a sale of receivables agreement. The ci pal Amount agreement allows AEP Credit to sell certain (in Com- Type of mil- Interest Due receivables and receive cash meeting the pany Debt lions) Rate Date requirements of SFAS 140 for the receivables Senior to be removed from AEP s and the APCo unsecured Notes 5 450 4.80% 2005 subsidiaries Balance Sheets. At December Seni or 31, 2002, AEP Credit had $454 million sold APCo unsecured Notes 200 4.32%* 2007 underthis agreement. See Note 23 forfurther Installment discussion. I&M Purchase 50 4.90% 2025 Contracts Senior Off-balance Sheet and Minority Interest I&M Unsecured 150 6.0% 2032 Notes Arrangements Seni or I&M unsecured 6 3/8% 2012 Notes 100 AEP and its subsidiaries enter into off-balance Seni or sheet arrangements for various reasons KPCo unsecured 125 5.50% 2007
. Notes ranging from accelerating cash collections, Seni or reducing operational expense to spreading KPCo unsecured 80 4.32%* 2007 Notes risk of loss to third parties. The following senior identifies significant off-balance sheet KPCo unsecured 70 4.37%* 2007 Notes arrangements:
Senior PSO unsecured 200 6.00% 2032 Notes Power Generation Facilitv Senior SWEPCo Unsecured 200 4.50% 2005 _ __ __ Notes AEP has entered into agreements with Katco other Notes 121 6.20%- 2017 subsid- Payable 6.60% Funding L.P. (Katco), an unrelated iaries unconsolidated special purpose entity. Katco other Revolving 0 Variable 2003 Subsid- credit has an aggregate financing commitment of iaries __________ bysubsidiary in
- Interest rate payable by Xsubsi ary in U.S.
_.S $525 million and a capital structure of which dollars. while these companies do nbt have an 3% is equity from investors with no Australian rate obligation, there is an relationship to AEP or any of its subsidiaries underlying interest rate to Australian investors in Australian dollars of either 6% and 97% is debt from a syndicate of banks. or a variable rate. Katco was formed to develop, construct, finance and lease a power generation facility The subsidiaries also redeemed to AEP. Katco will own the power generation approximately $2 billion of long-term debt in facility and lease it to AEP after construction is 2002. See the Schedule of Long-term Debt completed. The lease will be accounted for for each registrant in sections B to K for as an operating lease (see Note 22), therefore details. neither the facility nor the related obligations are reported on AEP s Consolidated Balance AEP uses money pools to meet the short-term Sheets. Payments underthe operating lease borrowings for the majority of its subsidiaries are expected to commence in the first quarter In addition, AEP also funds the short-term of 2004. AEP will in turn sublease the facility debt requirements of other subsidiaries that to Dow Chemical Company (DOW), which will are not included in the money pool. As of M-5
use the energy produced by the facility and increase. Annual payments of approximately sell excess energy. AEP has agreed to $12 million represent future minimum purchase the excess energy from DOW for payments during the initial term calculated resale. The use of Katco allows AEP to limit using the indexed LIBOR rate (1.38% at its risk associated with the power generation December 31, 2002). The Power Generation facility once the construction phase has been Facility collateralizes the debt obligation of completed. Katco. AEP s maximum exposure to loss as a result of its involvement with Katco is 100% AEP is the construction agent for Katco, and during the construction phase and up to 82% is responsible for completing construction by once the construction is completed. December 31, 2003, subject to unforeseen Maximum loss is deemed to be remote due to events beyond AEP s control. the collateralization. In the event the project is terminated before It is reasonably possible that AEP will completion of construction, AEP has the consolidate Katco in the third quarter of 2003, option to either purchase the facility for 100% as a result of the issuance of FASB of project costs or terminate the project and Interpretation No. 46 "Consolidation of make a payment to Katco for 89.9% of project Variable Interest Entities (FIN 46). Upon costs. consolidation, AEP would record the assets, liabilities, depreciation expense, minority The operating lease between Katco and AEP interest and debt interest expense. AEP commences on the commercial operation would eliminate operating lease expense. date of the facility and continues until The sublease to DOW would not be affected November 2006. The lease contains by this consolidation. extension options subject to the approval of Katco, and if all extension options were The lease payments and the guarantee of exercised, the total term of the lease would be construction commitments are included in the 30 years. AEP s lease payments to Katco are Other Commercial Commitments table below. sufficient for Katco to make required debt payments and provide a return to the Minoritv Interest in Finance Subsidiarv investors of Katco. At the end of each lease term, AEP may renew the lease at fair market In August 2001, AEP formed AEP Energy value subject to Katco s approval, purchase Services Gas Holding Co. II, LLC (SubOne) the facility at its original construction cost, or and Caddis Partners, LLC (Caddis). SubOne sell the facility, on behalf of Katco, to an is a wholly owned consolidated subsidiary of independent third party. If the facility is sold AEP that was capitalized with the assets of and the proceeds from the sale are Houston Pipe Line Company, Louisiana insufficient to repay Katco, AEP may be Interstate Gas Company (AEP subsidiaries) required to make a payment to Katco for the and $321.4 million of AEP Energy Services difference between the proceeds from the Gas Holding Company (AEP Gas Holding is sale and the obligations of Katco, up to 82% an AEP subsidiary and parent of SubOne) of the projects cost. AEP has guaranteed a preferred stock, that is convertible into AEP portion of the obligations of its subsidiaries to common stock at market price on a dollar-for-Katco during the construction and post- dollar basis. Caddis was capitalized with $2 construction periods. million cash and a subscription agreement that represents an unconditional obligation to As of December 31, 2002, project costs fund $83 million from SubOne and $750 subject to these agreements totaled $360 million from Steelhead Investors LLC million, and total costs for the completed ("Steelhead - non-controlling preferred facility are expected to be approximately $510 member interest). As managing member, million. For the 30 year extended lease term, SubOne consolidates Caddis. Steelhead is the lease rental is a variable rate obligation an unconsolidated special purpose entity and indexed to three-month LIBOR. Consequently has a capital structure of $750 million of which as market interest rates increase, the 3% is equity from investors with no payments under this operating lease will also relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. M-6
The use of Steelhead allows AEP to limit its member in Caddis. Upon the occurrence of risk associated with Houston Pipe Line certain events including a default in the Company and Louisiana Intrastate Gas payment of the preferred return, Steelhead s Company. rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the Under the provisions of the Caddis formation conversion of the AEP Gas Holding preferred agreements, Steelhead receives a quarterly stock into AEP common stock. If Steelhead preferred return equal to an adjusted floating exercised its rights to force Caddis to liquidate reference rate (4.784% and 4.413% for the under these conditions, then AEP would quarters ended December 31, 2002 and evaluate whether to refinance at that time or 2001, respectively). Caddis has the right to relinquish the assets that support the redeem Steelhead s interest at any time. intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP s The $750 million invested in Caddis by liquidity. Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August Caddis and SubOne are each alimited liability 2006, and is supported by the natural gas company, with a separate existence and pipeline assets of SubOne, a cash reserve identity from its members, and the assets of fund of SubOne and SubOne s $321.4 million each are separate and legally distinct from of preferred stock in AEP Gas Holding. The AEP. The results of operations, cash flows preferred stock is convertible into AEP and financial position of Caddis and SubOne common stock upon the occurrence of certain are consolidated with AEP for financial events including AEP s stock price closing reporting purposes. Steelhead s investment below $18.75 for ten consecutive trading in Caddis and payments made to Steelhead days. AEP can elect not to have the from Caddis are currently reported on AEP s transaction supported by such preferred stock income statement and balance sheet as if SubOne were to reduce its loan with Caddis Minority Interest in Finance Subsidiary. by $225 million. The credit agreement between Caddis and SubOne contains AEP s maximum exposure to loss as a result covenants that restrict certain incremental of its involvement with Steelhead is $321.4 liens and indebtedness, asset sales, million of preferred stock, $83 million under investments, acquisitions, and distributions. the subscription agreement to Caddis for any The credit agreement also contains covenants losses incurred by Caddis and the cash that impose minimum financial ratios. Non- reserve fund balance of $34 million (as of performance of these covenants may result in December 31, 2002) due Caddis for default an event of default under the credit under the intercompany loan agreement. agreement. Through December 31,2002, we AEP can reduce its maximum exposure have complied with the covenants contained related to the preferred stock by a reduction of in the credit agreement. In addition, a default $225 million of the intercompany loan. under any other agreement or instrument relating to AEP and certain subsidiaries debt As of December 31, 2002, management is outstanding in excess of $50 million is an continuing to review the application of FIN 46 event of default under the credit agreement. as it relates to the Steelhead transaction. The initial period of Steelhead s investment in AEP Credit Caddis is through August 2006. At the end of the initial period, Caddis will either reset AEP Credit entered into a sale of receivables Steelhead s return rate, re-market Steelhead s agreement with a group of banks and interests to new investors, redeem commercial paper conduits. Underthe sale of Steelhead s interests, in whole or in part receivables agreement, which expires May including accrued return, or liquidate Caddis 28, 2003, AEP Credit sells an interest in the in accordance with the provisions of receivables it acquires to the commercial applicable agreements. paper conduits and banks and receives cash. This transaction constitutes a sale of Steelhead has certain rights as a preferred receivables in accordance with SFAS 140 M-7
allowing the receivables to be taken off of the cost of administration. Neither OPCo nor AEP Credit s balance sheet and allowing AEP AEP has an ownership interest in JMG and Credit to repay any debt obligations. AEP has does not guarantee JMG s debt. no ownership interest in the commercial paper conduits and does not consolidate these At any time during the lease, OPCo has the entities in accordance with GAAP. We option to purchase the Gavin Scrubberforthe continue to service the receivables. This off- greater of its fair market value or adjusted balance sheet transaction was entered into to acquisition cost (equal to the unamortized allow AEP Credit to repay its outstanding debt debt and equity of JMG) or sell the Gavin obligations, continue to purchase the AEP Scrubber. The initial 15-year lease term is operating companies receivables, and non-cancelable. At the end of the initial term, accelerate its cash collections. OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), At December 31, 2002, the sale of or sell the Gavin Scrubber. In case of a sale receivables agreement provided the banks at less than the adjusted acquisition cost, and commercial paper conduits would OPCo must pay the difference to JMG. purchase a maximum of $600 million of receivables from AEP Credit, of which $454 The use of JMG allows OPCo to enter into an million was outstanding. As collections from operating lease while keeping the tax benefits receivables sold occur and are remitted, the otherwise associated with a capital lease. As outstanding balance for sold receivables is of December 31, 2002, unless the structure of reduced and as new receivables are sold, the this arrangement is changed, it is reasonably outstanding balance of sold receivables possible that AEP and OPCo will consolidate increases. All of the receivables sold JMG in the third quarter of 2003 as a result of represented affiliate receivables. The the issuance of FIN 46. Upon consolidation, commitments new term under the sale of AEP and OPCo would record the assets, receivables agreement will remain at $600 liabilities, depreciation expense, minority million until May 28, 2003. AEP Credit interest and debt interest expense of JMG. maintains a retained interest in the AEP and OPCo would eliminate operating receivables sold and this interest is pledged lease expense. AEP s and OPCo s as collateral for the collection of the maximum exposure to loss as a result of their receivables sold. The fair value of the involvement with JMG is approximately $560 retained interest is based on book value due million of outstanding debt and equity of JMG to the short-term nature of the accounts as of December 31, 2002. receivables less an allowance for anticipated uncollectible accounts. Rockport Plant Unit 2 AEGCo and l&M entered into a sale and See Note 23 "Lines of Credit and Sale of Receivables for further disclosure. leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee) Gavin Plant s flue gas desulfurization system an unrelated unconsolidated trustee for (Gavin Scrubber) Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP OPCo has entered into an agreement with or any of its subsidiaries and debt from a JMG Funding LLP (JMG) an unrelated unconsolidated special purpose entity. JMG syndicate of banks and securities in a private has a capital structure of which 3% is equity placement to certain institutional investors. from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from The gain from the sale was deferred and is pollution control bonds and other bonds. JMG being amortized over the term of the lease, owns the Gavin Scrubber and leases it to which expires in 2022. The Owner Trustee OPCo. The lease is accounted for as an owns the plant and leases it to AEGCo and operating lease with the payment obligations l&M. The lease is accounted for as an included in the lease footnote. Payments operating lease with the payment obligations under the operating lease are based on included in the lease footnote. The lease JMG s cost of financing (both debt and equity) term is for 33 years with potential renewal and include an amortization component plus options. At the end of the lease term, AEGCo M-8
and l&M have the option to renew the lease or in the Owner Trustee and do not guarantee its the Owner Trustee can sell the plant. debt. AEGCo, I&M norAEP has ownership interest Summary Obligation Information The contractual obligations of AEP and its subsidiaries include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes AEP s contractual cash obligations at December 31, 2002: Payments Due by Period (in millions) Contractual cash obligations Less Than 1 year 2-3 years 4 5 years After 5 years Total Long-term Debt $1,633 $1,817 $2,316 $4,354 $10,120 short-term Debt 3,164 - - - 3,164 Equity Unit Senior Notes - - 376 - 376 Trust Preferred Securities - - - 321 321 Minority Interest In Finance subsidiary (a) - - 759 - 759 Preferred Stock subject to Mandatory Redemption 84 84 capital Lease obligations 70 90 50 18 228 unconditional Purchase obligations (b) 1,405 1,810 989 1,513 5,717 Noncancellable operating Leases 305 523 479 2.462 3.769 Total contractual cash obligations SZS4Z2A0 S58 (a) The initial period of the preferred interest is through August 2006. At the end of the initial period, the preferred rate may be reset, the preferred member interests may be re-marketed to new investors, the preferred member interests may be redeemed, in whole or in part including accrued return, or the preferred member interest may be liquidated. (b) Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel. For the subsidiary registrants, please see each registrants schedules of capitalization and long-term debt included with each registrants financial statements in sections B through K for the timing of debt payment obligations and the lease footnote (Note 22) in section L for the timing of rent payments. The special purpose entities (SPE), described under 'Off-Balance Sheet and Minority Interest Arrangements above, have been employed for some of the contractual cash obligations reported in the above table. The lease of Rockport Plant Unit 2 and the Gavin Scrubber, the permanent financing of HPL, and the sale of accounts receivable all use SPEs. Neither AEP nor any AEP related parties have an ownership interest in the SPE. AEP does not guarantee the debt of these entities. These SPEs are not consolidated in AEP s or the subsidiaries financial statements in accordance with GAAP. As a result, neither the assets nor the debt of the SPE are included on AEP s Consolidated Balance Sheets. The future cash obligations payable to the SPEs are included in the above table. M-9
In addition to the amounts disclosed in the contractual cash obligations table above, AEP and its subsidiaries make commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. AEP s commitments outstanding at December 31,2002 underthese agreements are summarized in the table below: Amount of commitment Expiration Per Period (in millions) other commercial commitments Less Than 1 year 2-3 years 4 5 years After 5 years Total Standby Letters of Credit (a) $ 125 S 1 S- S 40 S 166 Guarantees of the Performance of outside Parties (b) 13 17 325 137 492 Guarantees of our Performance 1,159 2 82 9 1,252 Construction of Generating and Transmission Facilities for Third Parties (c) 671 83 47 67 868 other commercial Commitments Cd) 14 53 11 _ 78 Total Commercial commitments S15i6 SAi 1253 (a) AEP has standby letters of credit to third parties. These letters of credit cover gas and electricity trading contracts various construction contracts and credit enhancement for issued bonds. All of these letters of credit were issued at a subsidiary level of AEP in the subsidiaries ordinary course of business. The maximum future payments of these letters of credit are $166 million with maturities ranging from January 2003 to December 2007. There is no liability recorded for these letters of credit in accordance with FIN 45. since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiary as collateral. There is no recourse to third parties in the event these letters of credit are drawn. (b) These amounts are the balances drawn, not the maximum guarantee disclosed in Note 10. (c) AS construction agent for third party owners of power plants and transmission facilities, AEP has committed by contract terms to complete construction by dates specified in the contracts. should AEP default on these obligations, financial payments could be up to 100% of contract value (amount shown in table) or other remedies required by contract terms. (d) Represents estimated future payments for power to be generated at facilities under construction. M-10
With the exceptions of SWEPCo s guarantee Service issued a final environmental impact of an unaffiliated mine operators obligations statement and record of decision to allow the (payable upon their default) of $148 million at use of federal lands in the Jefferson National December 31, 2002, and OPCo s obligations Forest for construction of a portion of the line. under a power purchase agreement of $14 APCo expects additional state and federal million each year in 2003 through 2005, the permits to be issued in the first half of 2003. obligations in the above table are Through December 31, 2002, APCo has commitments of AEP and its non-registrant invested approximately $51 million in this subsidiaries. effort. The line is estimated to cost $287 million including amounts spent to date with OPCo has entered into a 30-year power completion in 2006. If the required permits purchase agreement for electricity pro-duced are not obtained and the line is not by an unaffiliated entitys three-unit natural constructed, the $51 million investment would gas fired plant. The plant was completed in be written off adversely affecting future results 2002 and the agreement will terminate in of operations and cash flows. 2032. Under the terms of the agreement, OPCo has the option to run the plant until Pension Plans December 31,2005 taking 100% of the power generated and making monthly capacity AEP maintains qualified defined benefit payments. The capacity payments are fixed pension plans (Qualified Plans), which cover through December 2005 at $1.2 million per substantially all non-union and certain union month. For the remainder of the 30 year associates, and unfunded excess plans to contract term, OPCo will pay the variable provide benefits in excess of amounts costs to generate the electricity it purchases permitted to be paid under the provisions of which could be up to 20% of the plants the tax law to participants in the Qualified capacity. The estimated fixed payments are Plans. Additionally, AEP has entered into included in the Other Commercial individual retirement agreements with certain Commitments table shown above. current and retired executives that provide additional retirement benefits. Expenditures for domestic electric utility construction are estimated to be $4 billion for AEP s pension income for all pension plans the next three years. Approximately 90% of approximated $69 million and $44 million for those construction expenditures are expected the years ended December 31, 2001 and to be financed by internally generated funds. December 31, 2002, respectively, and is calculated based upon a number of actuarial Construction expenditures for certain assumptions, including an expected long-term registrant subsidiaries for the next three years rate of return on the Qualified Plans assets of are: 9%. In developing the expected long-term rate of return assumption, AEP evaluated construction input from actuaries and investment Projected Expenditures Construction Financed with consultants, including their reviews of asset ExPenditures Internal Funds Ci millions) class return expectations as well as long-term inflation assumptions. Projected returns by APCo $1,005 70% I&M 601 90 such actuaries and consultants are based on OPCo 733 100 broad equity and bond indices. AEP also SWEPCo 351 100 TCC 419 100 considered historical returns of the investment markets as well as AEPs 10-year average APCo, AEP s subsidiary which operates in return (for the period ended 2002) of 8.8%. Virginia and West Virginia, has been seeking AEP anticipates that the investment regulatory approval to build a new high managers will continue to generate long-term voltage transmission line for over a decade. returns of at least 9.0%. The expected long-Certificates have been issued by both the term rate of return on the Qualified Plans WVPSC and the Virginia SCC authorizing assets is based on an asset allocation construction and operation of the line. On assumption of 70% with equity managers, December31,2002, the United States Forest with an expected long-term rate of return of M-11
10.5%, and 28% with fixed income managers, based on a review of long-term bonds that with an expected long-term rate of return of receive one of the two highest ratings given 6%, and 2% in cash and short term by a recognized rating agency. The discount investments with an expected rate of return of rate determined on this basis has decreased 3%. Because of market fluctuation, the actual from 7.25% at December 31, 2001 to 6.75% asset allocation as of December 31,2002 was at December 31, 2002. Due to the effect of 67% with equity managers and 32% with fixed the unrecognized actuarial losses and based income managers and 1% in cash. AEP on an expected rate of return on the Qualified believes, however, that the long-term asset Plans assets of 9.0%, a discount rate of allocation on average will approximate 70% 6.75% and various other assumptions, AEP with equity managers, 28% with fixed income estimates that the pension expense for all managers and the remaining 2% in cash. pension plans will approximate $2 million, $46 AEP regularly reviews the actual asset million and $97 million in 2003, 2004 and allocation and periodically rebalances the 2005, respectively. Future actual pension investments to our targeted allocation when expense will depend on future investment considered appropriate. AEP continues to performance, changes in future discount rates believe that 9.0% is a reasonable long-term and various other factors related to the rate of return on the Qualified Plans assets, populations participating in the pension plans. despite the recent market downturn in which the Qualified Plans assets had a loss of Lowering the expected long-term rate of 11.2% for the twelve months ended return on the Qualified Plans assets by.5% December 31, 2002. AEP will continue to (from 9.0% to 8.5%) would have reduced evaluate the actuarial assumptions, including pension income for 2002 by approximately the expected rate of return, at least annually, $19 million. Lowering the discount rate by and will adjust as necessary. 0.5% would have reduced pension income for 2002 by approximately $8 million. AEP bases its determination of pension expense or income on a market-related The value of the Qualified Plans assets has valuation of assets which reduces year-to- decreased from $3.438 billion at December year volatility. This market-related valuation 31, 2001 to $2.795 billion at December 31, recognizes investment gains or losses over a 2002. The Qualified Plans paid out $272 five-year period from the year in which they million in benefits to plan participants during occur. Investment gains or losses for this 2002 (nonqualified plans paid out $6 million in purpose are the difference between the benefits). The investment returns and expected return calculated using the market- declining discount rates have changed the related value of assets and the actual return status of the Qualified Plans from overfunded based on the market-related value of assets. (plan assets in excess of projected benefit Since the market-related value of assets obligations) by $146 million at December 31, recognizes gains or losses over a five-year 2001 to an underfunded position (plan assets period, the future value of assets will be are less than projected benefit obligations) of impacted as previously deferred gains or $788 million at December 31, 2002. Due to losses are recorded. As of December 31, the Qualified Plans currently being 2002 AEP had cumulative losses of underfunded, AEP recorded a charge to Other approximately $879 million which remain to be Comprehensive Income (OCI) of $585 million, recognized in the calculation of the market- and a Deferred Income Tax Asset of $315 related value of assets. These unrecognized million, offset by a Minimum Pension Liability net actuarial losses result in increases in the of $662 million and a reduction to prepaid future pension costs depending on several costs and intangible assets of $238 million. factors, including whether such losses at each The charge to OCI does not affect earnings or measurement date exceed the corridor in cash flow. AEP is in full compliance with all accordance with SFAS No. 87, "Employers regulations governing such plans including all Accounting for Pensions. Employee Retirement Income Security Act of 1974 laws. Because of the recent reductions The discount rate that AEP utilizes for in the funded status of the Qualified Plans, determining future pension obligations is AEP expects to make cash contributions to M-12
the Qualified Plans of approximately $66 events occur, for example, issuance of a million in 2003 increasing to approximately regulatory commission order or passage of $108 million per year by 2005. new legislation. If they determine that recovery of a regulatory asset is no longer Critical Accounting Policies probable, they write-off that regulatory asset as a charge against earnings. A write-off of In the ordinary course of business, AEP and regulatory assets may also reduce future cash its registrant subsidiaries have made a flows since there maybe no recovery through number of estimates and assumptions relating regulated rates. to the reporting of results of operations and financial condition in the preparation of their Traditional Electricity Supply and Delivery financial statements in conformity with Activities - Revenues are recognized on the accounting principles generally accepted in accrual or settlement basis for normal retail the United States of America. Actual results and wholesale electricity supply sales and could differ significantly from those estimates electricity transmission and distribution under different assumptions and conditions. delivery services. The revenues are They believe that the following discussion recognized in our statement of operations addresses the most critical accounting when the energy is delivered to the customer policies, which are those that are most and include unbilled as well as billed important to the portrayal of the financial amounts. In general, expenses are recorded condition and results and require when purchased electricity is received and managements most difficult, subjective and when expenses are incurred. complex judgments, often as a result of the need to make estimates about the effect of Domestic Gas Pipeline and Storage Activities matters that are inherently uncertain. Revenues are recognized from domestic gas pipeline and storage services when gas is Revenue Recognition delivered to contractual meter points or when services are provided. Transportation and Regulatory Accounting The consolidated storage revenues also include the accrual of financial statements of AEP and the financial earned, but unbilled and/or not yet metered statements of electric operating subsidiary companies with cost-based rate-regulated gas. operations (I&M, KPCo, PSO, and aportion of Substantially all of the forward gas purchase APCo, OPCo, CSPCo, TCC, TNC and and sale contracts, excluding wellhead SWEPCo) reflect the actions of regulators purchases of natural gas, swaps and options that can result in the recognition of revenues for the domestic pipeline operations, qualify and expenses in different time periods than as derivative financial instruments as defined enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these (deferred expenses to be recovered in the contracts to fair value during the period are future) and regulatory liabilities (deferred recognized currently in the results of future revenue reductions or refunds) are operations, appropriately discounted and net recorded to reflect the economic effects of of applicable credit and liquidity reserves. regulation by matching expenses with their recovery through regulated revenues in the Energy Marketing and Trading Activities In same accounting period and by matching 2000, 2001 and throughout the majority of income with its passage to customers through 2002, AEP engaged in broad non-regulated regulated revenues in the same accounting wholesale electricity, natural gas and other period. Regulatory liabilities are also commodity marketing and trading transactions recorded to provide for refunds to customers (trading activities). AEP s trading activities that have not yet been made. involved the purchase and sale of energy under forward contracts at fixed and variable When regulatory assets are probable of prices and the buying and selling of financial recovery through regulated rates, they record energy contracts which include exchange them as assets on the balance sheet. They traded futures and options and over-the-test for probability of recovery whenever new M-13
counter options and swaps. We used the the contract price and the market price as an mark-to-market method of accounting for unrealized gain or loss in revenues. In July trading activities as required by EITF Issue when the contract settles, we would realize a No. 98-10, Accounting forContracts Involved gain or loss in cash and reverse to revenues in Energy Trading and Risk Management the previously recorded cumulative unrealized Activities (EITF 98-10). Under the mark-to- gain or loss. Prior to settlement, the change market method of accounting, gains and in the fair value of physical forward sale and losses from settlements of forward trading purchase contracts is included in revenues on contracts are recorded net in revenues. For a net basis. Upon settlement of a forward energy contracts not yet settled, whether trading contract, the amount realized for a physical or financial, changes in fairvalue are sales contract and the realized cost for a recorded net as revenues. Such fair value purchase contract are included on a net basis changes are referred to as unrealized gains in revenues with the prior change in and losses from mark-to-market valuations. unrealized fair value reversed out of When positions are settled and gains and revenues. losses are realized, the previously recorded unrealized gains and losses from mark-to- For l&M, KPCo, PSO and a portion of TNC market valuations are reversed. Unrealized and SWEPCo, when the contract settles the mark-to-market gains and losses are included total gain or loss is realized in cash and the in the Balance Sheets as "Energy Trading and impact on the income statement depends on Derivative Contracts. In October 2002, whether the contracts delivery points are management announced plans to focus on within or outside of AEP s traditional wholesale markets where we own assets. A marketing area. For contracts with delivery portion of the revenues and costs associated points in AEP s traditional marketing area, the with AEP s wholesale electricity trading total gain or loss realized in cash for sales activities is allocated to TCC, SWEPCo, PSO and the cost of purchased energy are and TNC and to members of the AEP Power included in revenues on a net basis. Priorto Pool (APCo, CSPCo, I&M, KPCo and OPCo); settlement, changes in the fair value of however, TCC, SWEPCo, PSO and TNC are physical forward sale and purchase contracts only allocated a portion of the forward in AEP s traditional marketing area are transactions. deferred as regulatory liabilities (gains) or regulatory assets (losses). For contracts with AEP s cost-based rate-regulated electric delivery points outside of AEP s traditional public utility companies (I&M, KPCo, PSO, marketing area only the difference between and a portion of TNC and SWEPCo) defer, as the accumulated unrealized net gains or regulatory liabilities (unrealized gains) or losses recorded in prior periods and the cash regulatory assets (unrealized losses), proceeds is recognized in the income changes in the fair value of physical forward statement as nonoperating income. Prior to sale and purchase contracts in AEP s settlement, changes in the fair value of traditional marketing area. AEP s traditional physical forward sale and purchase contracts marketing area is up to two transmission with delivery points outside of AEP s systems from the AEP service territory. For traditional marketing area are included in contracts which are outside of AEP s nonoperating income on a net basis. traditional marketing area, the change in fair Unrealized mark-to-market gains and losses value is included in nonoperating income on a are included in the Balance Sheet as energy net basis. trading contract assets or liabilities as appropriate. The majority of trading activities represent physical forward contracts that are typically For APCo, CSPCo and OPCo, depending on settled by entering into offsetting contracts. whether the delivery point for the electricity is An example of our energy trading activities is in AEP s traditional marketing area or not when, in January, we enter into a forward determines where the contract is reported in sales contract to deliver energy in July. At the the income statement. Physical forward end of each month until the contract settles in trading sale and purchase contracts with July, we would record any difference between delivery points in AEP s traditional marketing M-14
area are included in revenues on a net basis. broker quotes. We mark-to-market open Prior to settlement, changes in the fair value long-term trading contracts based primarily on of physical forward sale and purchase valuation models that estimate future energy contracts in AEP s traditional marketing area prices based on existing market and broker are also included in revenues on a net basis. quotes and supply and demand market data Physical forward sale and purchase contracts and assumptions. The fairvalues determined for delivery outside of AEP s traditional are reduced by the appropriate valuation marketing area are included in nonoperating adjustments for items such as discounting, income when the contract settles. Prior to liquidity and credit quality. Credit risk is the settlement, changes in the fair value of risk that the counterparty to the contract will physical forward sale and purchase contracts fail to perform or fail to pay amounts due to with delivery points outside of AEP s AEP. Liquidity risk represents the risk that traditional marketing area are included in imperfections in the market will cause the nonoperating income on a net basis. price to be less than or more than what the price should be based purely on supply and Continuing with the above example for AEP, demand. There are inherent risks related to APCo, CSPCo, OPCo, TCC, and a portion of the underlying assumptions in models used to TNC and SWEPCo, assume that later in fair value open long-term trading contracts. January or sometime in Februarythrough July We have independent controls to evaluate the we enter into an offsetting forward contract to reasonableness of our valuation models. buy energy in July. If we do nothing else with However, energy markets, especially these contracts until settlement in July and if electricity markets, are imperfect and volatile. the commodity type, volumes, delivery point, Unforeseen events can and will cause schedule and other key terms match, then the reasonable price curves to differ from actual difference between the sale price and the prices throughout a contracts term and at the purchase price represents a fixed value to be time contracts settle. Therefore, there could realized when the contracts settle in July. be significant adverse or favorable effects on Mark-to-market accounting for these contracts future results of operations and cash flows if from this point forward will have no further market prices are not consistent with AEP s impact on operating results but has an approach at estimating current market offsetting and equal effect on trading contract consensus for forward prices in the current assets and liabilities. If the sale and purchase period. This is particularly true for long-term contracts do not match exactly as to contracts. commodity type, volumes, delivery point, schedule and other key terms, then there AEP applies MTM accounting to derivatives could be continuing mark-to-market effects on that are not trading contracts in accordance revenues from recording additional changes with generally accepted accounting principles. in fair values using MTM accounting. Derivatives are contracts whose value is derived from the market value of an For AEP, the trading of energy options, underlying commodity. futures and swaps, represents financial transactions with unrealized gains and losses Volatility in energy commodities markets from changes in fair values reported net in affects the fair values of all of our open revenues until the contracts settle. When trading and derivative contracts exposing us these contracts settle, we record the net to market risk and causing our results of proceeds in revenues and reverse to operations to be subject to volatility. See revenues the prior cumulative unrealized net Note 17, "Risk Management, Financial gain or loss. APCo, CSPCo, I&M, KPCo and Instruments and Derivatives for a discussion OPCo also have financial transactions, but of the policies and procedures used to record the unrealized gains and losses, as manage our exposure to market and other well as the net proceeds upon settlement, in risks from trading activities. nonoperating income. Given the previously discussed reduction in The fair values of open short-term trading AEP s trading activities, the impact of mark-to-contracts are based on exchange prices and market accounting on ourfinancial statements M-15
= is expected to decline in future periods. Market Risks Long-Lived Assets As a major power producer and marketer of wholesale electricity and natural gas, we have Long-lived assets, including fixed assets and certain market risks inherent in our business intangibles, are evaluated periodically for activities. These risks include commodity impairment whenever events or changes in price risk, interest rate risk, foreign exchange circumstances indicate that the carrying risk and credit risk. They represent the risk of amount of any such assets may not be loss that may impact us due to changes inthe recoverable. If the sum of the undiscounted underlying market prices or rates. cash flows is less than the carrying value, we recognize an impairment loss, measured as Policies and procedures have been the amount by which the carrying value established to identify, assess, and manage exceeds the fair value of the asset. The market risk exposures in our day to day estimate of cash flow is based upon, among operations. Our risk policies have been other things, certain assumptions about reviewed with the Board of Directors, expected future operating performance. Our approved by a Risk Executive Committee and estimates of undiscounted cash flow may administered by a Chief Risk Officer. The differ from actual cash flow due to, among Risk Executive Committee establishes risk other things, technological changes, limits, approves risk policies, assigns economic conditions, changes to its business responsibilities regarding the oversight and model or changes in its operating management of risk and monitors risk levels. performance. This committee receives daily, weekly, and monthly reports regarding compliance with Pension Benefits policies, limits and procedures. The committee meets monthly and consists of the AEP sponsors pension and other retirement Chief Risk Officer, Chief Credit Officer, V.P. plans in various forms covering substantially Market Risk Oversight, and senior financial all employees who meet eligibility and operating managers. requirements. Several statistical and other factors which attempt to anticipate future We use a risk measurement model which events are used in calculating the expense calculates Value at Risk (VaR) to measure and liability related to the plans. These our commodity price risk in the trading factors include assumptions about the portfolio. The VaR is based on the variance - discount rate, expected return on plan assets covariance method using historical prices to and rate of future compensation increases as estimate volatilities and correlations and determined by management, within certain assuming a 95% confidence level and a one-guidelines. In addition, AEP s actuarial day holding period. Based on this VaR consultants also use subjective factors such analysis, at December 31, 2002 a near term as withdrawal and mortality rates to estimate typical change in commodity prices is not these factors. The actuarial assumptions expected to have a material effect on our used may differ materially from actual results results of operations, cash flows or financial due to changing market and economic condition. The following table shows the high, conditions, higher orlowerwithdrawal rates or average, and low market risk as measured by longer or shorter life spans of participants. VaR at: These differences may result in a significant December 31, impact to the amount of pension expense 2002 2001 High Average Low High Average Low recorded. (in millions) AEP $24 $12 $4 S28 $14 $5 New Accounting Pronouncements APCO 4 1 4 1 CSPCo 3 I1 2 1 See Note 1 to the consolidated financial I&N 3 I 3 1 statements for a discussion of significant KPCo 1 1 OPCo 4 I1 3 1 accounting policies and new accounting Pso 2 1 SWEPCo 3 1 pronouncements. TCC 3 1 TNC 1 1 M-16
After the October announcement of our protection afforded by fuel clause recovery strategy to reduce trading activity, the related mechanisms has either been eliminated by VaRs were substantially reduced. The the implementation of customer choice in average AEP trading VaR for the fourth Ohio (effective January 1, 2001 for CSPCo quarter 2002 was $7 million as compared to and OPCo) and in the ERCOT area of Texas $13 million for fourth quarter 2001. In 2003 (effective January 1, 2002 for TCC and TNC) we will continue to adjust our VaR limit or frozen by settlement agreements in structure commensurate with our anticipated Michigan and West Virginia or capped in level of trading activity. Indiana. To the extent the fuel supply of the generating units in these states is not under We also utilize a VaR model to measure fixed price long-term contracts AEP is subject interest rate market risk exposure. The to market price risk. AEP continues to be interest rate VaR model is based on a Monte protected against market price changes by Carlo simulation with a 95% confidence level active fuel clauses in Oklahoma, Arkansas, and a one year holding period. The volatilities Louisiana, Kentucky, Virginia and the SPP and correlations were based on three years of area of Texas. weekly prices. The risk of potential loss in fair value attributable to AEP's exposure to We employ physical forward purchase and interest rates, primarily related to long-term sale contracts, exchange futures and options, debt with fixed interest rates, was $527 million over-the-counter options, swaps, and other at December 31, 2002 and $673 million at derivative contracts to offset price risk where December 31, 2001. However, since we appropriate. However, we engage in trading would not expect to liquidate our entire debt of electricity, gas and to a lesser degree other portfolio in a one year holding period, a near commodities and as a result we are subject to term change in interest rates should not price risk. The amount of risk taken by the materially affect results of operations or traders is controlled by the management of consolidated financial position. the trading operations and the Companys Chief Risk Officer and his staff. When the risk The following table shows the potential loss in from trading activities exceeds certain pre-fair value as measured by VaR allocated to determined limits, the positions are modified the AEP registrant subsidiaries based upon or hedged to reduce the risk to be within the debt outstanding: limits unless specifically approved bythe Risk Executive Committee. VaR for Registrant Subsidiaries: We employ fair value hedges, cash flow December 31. 2002 2001 hedges and swaps to mitigate changes in (in millions) interest rates or fair values on short and long-company AEGCo S 3 S 5 term debt when management deems it APCo 87 100 necessary. We do not hedge all interest rate CSPCo 33 60 I&M 85 86 risk. KPCo 30 16 OPCo 34 59 PSO 70 17 We employ cash flow forward hedge contracts SWEPCo 70 36 to lock-in prices on certain power trading TCC 65 80 TNC 5 20 transactions denominated in foreign currencies where deemed necessary. AEGCo is not exposed to risk from changes in International subsidiaries use currency swaps interest rates on short-term and long-term to hedge exchange rate fluctuations in debt borrowings used to finance operations since denominated in foreign currencies. We do financing costs are recovered through the unit not hedge all foreign currency exposure. power agreements. Credit Risk AEP is exposed to risk from changes in the market prices of coal and natural gas used to AEP limits credit risk by extending unsecured generate electricity where generation is no credit to entities based on internal ratings. In longer regulated or where existing fuel addition, AEP uses Moody s Investor Service, clauses are suspended or frozen. The M-17
Standard and Poors and qualitative and cash related instruments to be deposited on quantitative data to independently assess the these transactions as margin against open financial health of counterparties on an positions. The combined margin deposits at ongoing basis. This data, in conjunction with December 31, 2002 and 2001 were the ratings information, is used to determine $109 million and $55 million, respectively. appropriate risk parameters. AEP also These margin accounts are restricted and requires cash deposits, letters of credit and therefore are not included in Cash and Cash parental/affiliate guarantees as security from Equivalents on the Balance Sheets. We can counterparties depending upon credit quality be subject to further margin requirements in our normal course of business. should related commodity prices change. We trade electricity and gas contracts with We recognize the net change in the fair value numerous counterparties. Since our open of all open trading contracts, in accordance energy trading contracts are valued based on with generally accepted accounting principles changes in market prices of the related and include the net change in mark-to-market commodities, our exposures change daily. We amounts on a net discounted basis in believe that our credit and market exposures revenues. The marking-to-market of open with any one counterparty is not material to trading contracts contributed an unrealized our financial condition at December 31, 2002. $180 million to revenues in 2002. The mark-At December 31, 2002 approximately 7% of to-market fair values of open short-term our exposure was below investment grade as trading contracts are based on exchange expressed in terms of net MTM assets. Net prices and broker quotes. The fair value of MTM assets represents the aggregate open long-term trading contracts are based difference between the forward market price mainly on internally developed valuation for the remaining term of the contract and the models. The gross value is present valued contractual price per counterparty. As of and reduced by appropriate valuation December 31, 2002, the following table adjustments for counterparty credit risks and approximates counterparty credit quality and liquidity risk to arrive at fair value. The exposure for AEP based on netting across models are derived from internally assessed AEP entities, commodities and instruments: market prices with the exception of the NYMEX gas curve, where we use daily settled Futures, prices. Forward price curves are developed Counterparty Forward and Credit Quality. Swap Contracts Options Total for inclusion in the model based on broker quotes and other available market data. The (in millions) liquid portion of these curves are validated on AAA/Exchanges $ 26 $ 2 $ 28 AA 307 33 340 a regular basis by the middle-office through A 448 26 474 the market data. Illiquid portions of the curves BBB 700 101 801 are validated through a review of the Below Investment Grade 107 11 118 underlying market assumptions and variables for consistency and reasonableness. The end Total SUH $173 $IZMi of the month liquidity reserve is based on the difference in price between the price curve The counterparty credit quality and exposure and the bid price if we have a long position for the registrant subsidiaries is generally and the price curve and the ask price if we consistent with that of AEP. have a short position. This provides for a more accurate valuation of energy contracts. We enter into transactions for electricity and natural gas as part of wholesale trading The use of these models to fair value open operations. Electric and gas transactions are trading contracts has inherent risks relating to executed over the counter with counterparties the underlying assumptions employed by such or through brokers. Gas transactions are also models. Independent controls are in place to executed through brokerage accounts with evaluate the reasonableness of the price brokers who are registered with the curve models. Significant adverse or Commodity Futures Trading Commission. favorable effects on future results of Brokers and counterparties require cash or operations and cash flows could occur if M-18
market prices, at the time of settlement, do The following table shows net revenues not correlate with our interally developed price (revenues less fuel and purchased energy models. expense) and their relationship to the mark-to-market revenues (the change in fair value of The effect on the Statements of Operations of open trading contracts). marking to market open electricity trading contracts in AEP s regulated jurisdictions, 2002 December 31. 2001 2000 specifically l&M, KPCo, PSO and a portion of (in millions) Revenues SWEPCO, is deferred as regulatory assets (including (losses) or liabilities (gains) since these Mark- To-Market transactions are included in cost of service on Adjustment) S14,555 S12,767 S11,113 a settlement basis for ratemaking purposes. Fuel and Purchased Unrealized mark-to-market gains and losses Energy Expense 6 307 4.944 3 880 from trading are reported as assets or Net Revenues La .248 SIIL.823 LL2II liabilities. Mark-to-Market Revenues Sin $20 si87 Percentage of Net Revenues Represented by Mark-to-Market on Open Trading Positions 2% 3% 3X M-19
The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts shows how the net fair value of energy trading contracts was derived from the amounts included in the Consolidated Balance Sheets line item 'Energy Trading and Derivative Contracts. The next table "Mark-to-Market EnergyTrading and Derivative Contracts disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts and related derivatives at December 31, 2001 of $448 million to December 31, 2002 of $250 million. Contracts realized/settled during the period include both sales and purchase contracts. The third 'table "Mark-to-Market Energy Trading and Derivative Contract Maturities shows exposures to changes in fair values and realization periods over time for each method used to determine fair value. Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts - AEP December 31 2002 2001 (in millions) Energy Trading and Derivative contracts: current Asset $1,046 S 2,125 Long-term Asset 824 795 current Liability (1,147) (1,877) Long-term Liability (484) (603) Net Fair value of Energy Trading and Derivative contracts 239 440 Non-trading related derivative liabilities 11* - Assets held for sale (citipower) - 8 Net Fair value of Energy Trading and Derivative contracts S-250 A448
- Excludes $6 million Loss recorded in an equity investment.
The above net fair value of energy trading and derivative contracts includes $180 million at December 31, 2002, in unrealized mark-to-market gains that are recognized in the Consolidated Statements of Operations at December 31, 2002. Mark-to-Market Energy Trading and Derivative Contracts AEP Total (in millions) Net Fair value of Energy Trading and Derivative contracts at December 31, 2001 $ 448 (Gain) LOSS from contracts Realized/settled During the Period (182) (a) Fair value of New open Contracts when Entered Into During the Period 68 (b) Net option Premiums Paid/(Received) (130) cc) change in fair value due to Methodology changes 1 (d) change in Market value of Energy Trading Contracts Allocated to Regulated Jurisdictions (2) (e) changes in Market value of contracts 47 (f) Net Fair value of Energy Trading and Derivative contracts at December 31, 2002 S-250 M-20
Mark-to-Market Energy Trading and Derivative Contracts Registrant Subsidiaries APCO CSPCo I&M Net Fair value of Energy Trading Contracts at December 31, 2001 75,701 S 48,449 S61,345 (Gain) Loss from contracts Realized/Settled During the Period (a) (19,143) (13,812) (9,611) change in Fair value Due TO Methodology changes (d) 350 228 247 changes in Fair. Market Value of Energy Trading contracts Allocated To Regulated Jurisdictions (e) - - 1,502 Fair value of New Open contracts when Entered Into during The Period (b) 10,865 7,039 2,774 Net option Premium Payments (c) (1,797) (1,208) (1,292) changes In Market value of Contracts (f) 30.876 24.421 15,896 Net Fair Value of Energy Trading contracts at December 31, 2002 (g) 96 7 KPCO OPCO PSO Net Fair value of Energy Trading contracts at December 31, 2001 $12,729 S 65,446 S 2,434 (Gain) LOSS From contracts Realized/settled During Period (a) 1,153 (18,337) 6,476 Change in Fair value Due To Methodology changes (d) 90 311 32 Changes In Fair Market value of Energy Trading contracts Allocated To Regulated jurisdiction (e) 5,136 (5,397) Fair value of New open contracts when Entered Into During Period (b) 1,013 18,443 Net option Premium Payments (c) (464) (1,603) changes In Market value of contracts (f) 5.341 29.846 - Net Fair value of Energy Trading contracts at December 31, 2002 (g) IS9 SWEPCo TCC TNC Net Fair value of Energy Trading Contracts at December 31, 2001 S 2,900 S 3,857 S 915 (Gain) Loss From contracts Realized/Settled During The Period (a) 6,971 7,138 2,413 change in Fair value Due To Methodology changes (d) 36 42 12 changes In Fair Market value of Energy Trading contracts Allocated To Regulated jurisdiction (e) (2,485) - (336) Fair value of New open Contracts when Entered Into During The Period Cb) 428 1,919 1,627 Net option Premium Payments (c) - - changes In Market value of contracts (f) (3.800) (7.542) (2.588) Net Fair Value of Energy Trading contracts at December 31, 2002 (g) (a) "(Gain) LOss from contracts Realized/settled During the Period include realized gains from energy trading contracts and related derivatives that settled during 2002 that were entered into prior to 2002. (b) The "Fair value of New Open Contracts when Entered Into During Period represents the fair value of long- term contracts entered into with customers during 2002. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves representative of the delivery location. Cc) Net option Premiums Paid/(Received) reflects the net option premiums paid/Creceived) as they relate to unexercised and unexpired option contracts that were entered into in 2002 (d) The company changed the discount rate applied to its trading portfolio from BBB+ utility to LIBOR in the second quarter which increased fair value by $10 million. In addition, the Company changed its methodology in valuing a spread option model so as to more accurately reflect the exercising of power transactions at optimal prices which reduced fair value by $9 million. (e)"change in Market value of Energy Trading contracts Allocated to Regulated Jurisdictions relates to the net gains of those contracts that are not reflected in the consolidated Statements of operations. These net gains are recorded as regulatory liabilities for those subsidiaries that operate in regulated jurisdictions. (f)"Changes in Market value of contracts represents the fair value change in the trading portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. (g) Net Fair value of Energy Trading contracts does not reflect the changes in fair value associated with derivative contracts designated as hedges and therefore will not agree to the net fair value of the Energy Trading and Derivative contracts line items on the individual registrants balance sheets. M-21
Mark-to-Market Energy Trading and Derivative Contract Maturities - AEP Fair value of Contracts at December 31. 2002 Maturities (in m11lions) AEP Consolidated Less than In Excess Total Fair source of Fair value 1 Year 1-3 years 4-5 years of 5 years value Prices Actively Quoted (a) S(32) S 69 S- S - $ 37 Prices Provided by other External Sources (b) 24 189 11 224 Prices Based on Models and other valuation Methods (c) C8) 13 36 24 -- l) Total RU) 12m SAZ Mark-to-Market Energy Trading and Derivative Contract Maturities Registrant Subsidiaries Fair value of Contracts at December 31. 2002 Maturities (in thousands) Less than In Excess Total Fair source of Fair value 1 year 1-3 years 4-5 years of 5 years value APCo Prices Provided by other External Sources (b) $14,352 $43,307 S 3,018 S - S 60,677 Prices Based on Models and other Valuation Methods (c) 11.492 9,475 8.183 7.025 36.175 Total Sj5'.474 Si2.182 S11,201QZ L705 i96,852 CSPCo Prices Provided by other External Sources (b) $ 9,657 $29,113 S 2,028 S - S 40,798 Prices Based on Models and other valuation Methods (c) 7.726 6.370 5,501 4.722 24 319 Total S7,52 KPCo Prices Provided by other External Sources (b) S 3,707 $11,176 S 779 S- S 15,662 Prices Based on Models and other valuation Methods (c) 2.9665 2.442 2.114 1A 9.336 Total i 6,67 S13,6i18 2,9 kiS 1,8i1= S2,9 I&M Prices Provided by other External sources (b) $12,105 $30,961 S 2,171 5- S 45,237 Prices Based on Models and other valuation Methods (c) 7.913 6.772 5 053 25, 624 Total S37,7i3 S,886 SlsQB OPCo Prices Provided by other External Sources (b) $20,775 $38,622 $ 2,691 $ - S 62,088 Prices Based on Models and other valuation Methods (c) 10 003 8.453 7.298 6.264 32.018 Total 1k077S S4707 $4S 9,989 56>4 t 94410 PSO Prices Provided by other External Sources (b) $ 373 S1,736 s 125 S 2,234 Prices Based on Models and other Valuation Methods (c) 296 390 336 289 1 311 Total i-A461 SWEPCo Prices Provided by other External Sources (b) S 427 $1,983 S 141 $ - S 2,551 Prices Based on Models and other valuation Methods (c) 338 446 385 330 1.499 Total 1__3Q 405 TCC Prices Provided by other External Sources (b) S 1,536 $ 1,605 $ 115 S - $ 3,256 Prices Based on Models and other valuation Methods (c) S1 1.219 2,75 361 311 267 2.158 Total -1,966 L 426 S 267 M-22
TNC Prices Provided by other External Sources (b) S 201 $1,016 S 73 $ - S 1,290 Prices Based on Models and other valuation Methods (c) 159 229 197 168 753 Total 5 360 SIZM4 S270 S168 512A84 (a)"Prices Actively Quoted represents the Company s exchange traded futures positions. (b)"Prices Provided by other External sources represents the company s positions in natural gas, power, and coal at points where over-the-counter broker quotes are available. some prices from external sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this category. (c)"Prices Based on Models and other valuation Methods contain the following: the value of the company s adjustments for liquidity and counterparty credit exposure, the value of contracts not quoted by an exchange or an over-the-counter broker, the value of transactions for which an internally developed price curve was developed as a result of the long dated nature of certain transactions, and the value of certain structured transactions. M-23
= We have investments in debt and equity affected by restructuring legislation is securities which are held in nuclear trust presented in Note 8 of the Notes to Financial funds. The trust investments and their fair Statements. value are discussed in Note 17, "Risk Management, Financial Instruments and CorporateSeparation Derivatives. Financial instruments in these trust funds have not been included in the AEP and its subsidiaries have filed with the market risk calculation for interest rates as FERC and SEC seeking approval to separate these instruments are marked-to-market and their regulated and unregulated operations. changes in market value of these instruments The plan for corporate separation allows AEP are reflected in a corresponding and its subsidiaries to meet the requirements decommissioning liability. Any differences of Texas and Ohio restructuring legislation. In between the trust fund assets and the ultimate Texas, TCC and TNC intended to transferthe liability are expected to be recovered through generation assets from the integrated electric regulated rates from our regulated customers. operating companies (CPL and WTU) which operated in ERCOT prior to the effective date Inflation affects our cost of replacing operating of the Texas Restructuring Legislation to and maintaining utility plant assets. The rate- unregulated generation companies. In Ohio, making process limits recovery to the CSPCo and OPCo intended to transfer historical cost of assets, resulting in economic transmission and distribution assets from the losses when the effects of inflation are not integrated companies to two new wires recovered from customers on a timely basis. companies leaving CSPCo and OPCo as However, economic gains that result from the generating companies. AEP and its repayment of long-term debt with inflated subsidiaries proposed amendments to the dollars partly offset such losses. power pooling agreements to remove the four Ohio and Texas generating companies. Only Industry Restructuring those operating companies that continue to exist as integrated utilities would have been Four of the eleven state retail jurisdictions included in the amended power pooling (Michigan, Ohio, Texas and Virginia) in which agreements, which would govern energy AEP s domestic electric utility companies exchanges among members and the operate have implemented retail restructuring allocation of their off-system purchases and legislation. Three other states (Arkansas, sales. In connection with corporate Oklahoma and West Virginia) initially adopted seperation, certain new interim power supply retail restructuring legislation, but have since agreements have been proposed to provide delayed the implementation of that legislation power to distribution companies who will no or repealed the legislation (Arkansas). In longer own generation assets. Several state general, retail restructuring legislation commissions, wholesale customer groups and provides for a transition from cost-based rate other interested parties intervened in the regulation of bundled electric service to FERC proceeding. Negotiated settlement customer choice and market pricing for the agreements with the state regulatory supply of electricity. As legislative and commissions and other major intervenors regulatory proceedings evolved, six AEP were filed with the FERC in December 2001. electric operating companies (APCo, CSPCo, In September 2002, the FERC conditionally OPCo, SWEPCo, TCC and TNC) have approved our corporate separation plan as discontinued the application of SFAS 71 modified by the settlement agreements. regulatory accounting for the generation Terms in the settlement agreements would be business. AEP has not discontinued its effective upon implementation of corporation regulatory accounting for its subsidiaries separation. In addition, SEC approval of doing business in Michigan (I&M) and AEP s corporate separation plan is required Oklahoma (PSO). Restructuring legislation, for its implementation. The Arkansas the status of the transition plans and the Commission intervened with the SEC, which status of the electric utility companies has extended the length of time needed for accounting to comply with the changes in the SEC s review. In order to execute this each of our state regulatory jurisdictions separation, AEP and its subsidiaries may be M-24
required to retire various debt securities and notified the FERC of their intent that the transfer assets between legal entities. transmission assets in SPP would participate in MISO. AEP s SPP companies are also With the changes in AEP s business strategy regulated by state public utility commissions, in response to current energy and the Louisiana and Arkansas commissions market/business conditions, management is also filed responses to the FERC s RTO order evaluating changes to the corporate indicating that additional analysis was separation plans, including determining required. Regulatory activities concerning whether legal corporate separation is various RTO issues are ongoing in Arkansas appropriate. and Louisiana. RTO Formnation Management isunable to predict the outcome of these transmission regulatory actions and FERC Order No. 2000 and many of the proceedings or their impact on the timing and settlement agreements with the FERC and operation of RTOs, AEP and its subsidiaries state regulatory commissions to approve the transmission operations or future results of AEP-CSW merger required the transfer of operations and cash flows. functional control of the subsidiaries transmission systems to RTOs. FERC Proposed Standard Market Design and Security Standards AEP East companies initially participated in the formation of the Alliance RTO. In In 2002, the FERC issued its Standard Market December 2001, the FERC reversed prior Design (SMD) notice of proposed rulemaking approvals and rejected the Alliance RTO s seeking to standardize the structure and filing. Subsequently, in May 2002, AEP operation of wholesale electricity markets announced an agreement with the PJM across the country. The FERC published for Interconnection to pursue terms for AEP East comment its proposed security standards as companies to participate in PJM with final part of the SMD. These standards are agreements to be negotiated. In July 2002, intended to ensure all market participants the FERC conditionally approved AEP s have a basic security program that effectively decision forAEP East companies to join PJM protects the electric grid and related market subject to certain conditions being met. The activities. Because the rule is not yet performance of these conditions are only finalized, management cannot predict the partially under AEP s control. In December effect of the final rule on AEP or its 2002, AEP East companies in Indiana, subsidiaries operations and financial results. Kentucky, Ohio and Virginia filed for state See Note 9 fora complete discussion of these regulatory commission approval of their plans proposals. to transfer functional control of their transmission assets to PJM based on Litigation statutory or regulatory requirements in those states. Those proceedings are currently AEP and its subsidiaries are involved in pending. In February 2003, the Virginia various litigation. The details of significant Legislature enacted legislation that would litigation contingencies are disclosed in Note prohibit the transfer to an RTO, until at least 9 and summarized below. July 2004, which is currently awaiting signature by the Governor of Virginia. Enron Bankruptcy Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo AEP West companies are members of ERCOT or the SPP. In May 2002, FERC In 2002, certain subsidiaries of AEP filed accepted, conditionally, filings related to a claims in the bankruptcy proceeding of the proposed consolidation of the MISO and the Enron Corp. and its subsidiaries which are SPP. In that order the FERC required the pending in the U.S. Bankruptcy Court for the AEP West companies in SPP to file reasons Southern District of New York. At the date of why they should not be required to join MISO. Enron s bankruptcy, AEP and its subsidiaries In August 2002, AEP, SWEPCo and TNC had open trading contracts and trading M-25
accounts receivables and payables with The earnings reductions for affected Enron and various HPL related contingencies registrant subsidiaries were as follows: and indemnities including issues related to the underground Bammel gas storage facility and (in millions) the cushion gas (or pad gas) required for its APCO S 82 normal operation. CSPCo 41 I&M 66 In 2001, AEP expensed $47 million ($31 KPCO 8 million net of tax) for our estimated loss from OPCo 118 the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a AEP has appealed the Courts decision. See cumulative loss of $53 million ($34 million net Note 18 for further discussion. of tax). The amounts for certain subsidiary registrants were: Shareholders Litigation Affecting AEP Amounts In 2002, lawsuits alleging securities law Amounts Net of violations, a breach of fiduciary duty forfailure Registrant Exoensed Tax to establish and maintain adequate internal (in millions) controls and violations of the Employee Retirement Income Security Act were filed APCo S5.3 $3.4 against AEP, certain AEP executives, CSPCo 2.7 1.8 members of the AEP Board of Directors and I&M 2.8 1.8 certain investment banking firms. These KPCO 1.1 0.7 cases are in the initial pleading stage. AEP oPco 3.6 2.3 intends to vigorously defend against these actions. See Note 9 for further discussion. The additional 2002 expense did not materially change the cumulative expense per CaliforniaLawsuit Affecting AEP registrant subsidiary. The amounts expensed were based on an analysis of contracts where In2002, the Lieutenant Govemorof California AEP entities and Enron are counterparties. filed a lawsuit in California Superior Court against forty energy companies, including Management believes that we have the right AEP, and two publishing companies alleging to utilize offsetting receivables and payables violations of California law through alleged and related collateral across various Enron fraudulent reporting of false natural gas price entities by offsetting approximately $110 and volume information with an intentto affect million of trading payables owed to various the market price of natural gas and electricity. Enron entities against trading receivables due AEP intends to vigorously defend against this action. See Note 9 for further discussion. to us. Management believes we have legal defenses to any challenge that may be made FERC Wholesale Fuel Complaints Affecting to the utilization of such offsets. At this time AEP and TNC management is unable to predict the ultimate resolution of these issues or their impact on In May 2000 and November 2001, certain results of operations and cash flows. See TNC wholesale customers filed a complaints Note 9 for further discussion. with FERC alleging that TNC had overcharged them through the fuel adjustment COLI Affecting AEP, APCo, CSPCo, I&M, clause for certain purchased power costs. KPCo and OPCo The final resolution of this matter could have a negative impact on futute results of A decision by the U.S. District Court for the operations, cash flow and financial condition. Southern District of Ohio in February 2001 See Note 6 for further discussion. that denied AEP s deduction of interest claimed on AEP s consolidated federal Merger Litigation Affecting AEP and all income tax returns related to a COLI program SubsidiaryRegistrants resulted in a $319 million reduction in AEP s Net Income for 2000. In January 2002, a federal court ruled that the M-26
SEC did not properly find that the June 15, FERC issued an order delaying the effective 2000 merger of AEP with CSW meets the date of the mitigation plan until after a requirements of the PUHCA and sent the planned technical conference on market case back to the SEC for further review. power determination. No such conference Management believes that the merger meets has been held and management is unable to the requirements of the PUHCA and expects predict the timing of any further action by the the matter to be resolved favorably. See Note FERC or its affect on future results of 9 for further discussion. operations and cash flows. Arbitration of Williams Claim Affecting AEP Other Litigation Affecting AEP and all Subsidiary Registrants In 2002, AEP filed its demand for arbitration with the American Arbitration Association to AEP and its subsidiaries are involved in a initiate formal arbitration proceedings in a number of other legal proceedings and dispute with the Williams Companies claims. While management is unable to (Williams). The proceeding results from predict the outcome of such litigation, it is not Williams repudiation of its obligations to expected that the ultimate resolution of these provide physical power deliveries to AEP and matters will have a material adverse effect on Williams failure to provide the monetary results of operations, cash flows or financial security required for natural gas deliveries. condition. Although management is unable to predict the outcome of this matter, it is not expected to Environmental Concerns and Issues have a material impact on results of operations, cash flows or financial condition. AEP and its subsidiaries will confront several See Note 9 for further discussion. new environmental requirements over the next decade with the potential for substantial Energy Market Investigations AffectingAEP control costs and premature retirement of some generating plants. These policies During 2002, the FERC, the California include: stringent controls on sulfur dioxide attorney general, the PUCT, the SEC, the (S02), nitrogen oxide (NOx) and mercury (Hg) Department of Justice and the U.S. emissions from future regulations or laws, or Commodity Futures Trading Commission an adverse decision in the New Source (CFTC) initiated investigations into whether Review litigation; a new Clean Water Act rule any entity, including Enron, manipulated to reduce fish killed at once-through cooled short-term prices in electric energy or natural power plants; and a possible future gas markets, exercised undue influence over requirement to reduce carbon dioxide (C02) wholesale prices or participated in fraudulent emissions as the world endeavors to stabilize trading practices. atmospheric concentrations of greenhouse gas emissions and avert global climatic AEP and its subsidiaries have and will changes. continue to provide information to the FERC, the SEC, state officials and the CFTC as AEP and its subsidiaries environmental policy required. See Note 9 for further discussion. require full compliance with all applicable legal requirements. In support of this policy, FERC Market Power Mitigation Affecting AEP and its subsidiaries invest in research the AEP System through groups like the Electric Power Research Institute and directly through A FERC order on our triennial market based demonstration projects for new emission wholesale power rate authorization update control technologies. AEP and its required certain mitigation actions that AEP subsidiaries intend to continue in a leadership and its subsidiaries would need to take for role to protect and preserve the environment sales/purchases within their control area and while providing vital energy commodities and required the posting of information on our services to customers at fair prices. website regarding the status of AEP s power AEP and its subsidiaries have a proven system. As a result of a request for rehearing record of efficiently producing and delivering filed by AEP and other market participants, M-27
electricity and gas while minimizing the impact matters due to the number of alleged on the environment. AEP and its subsidiaries violations and the significant number of issues have spent billions of dollars to equip many of yet to be determined by the Court. If the AEP their facilities with pollution control System companies do not prevail, any capital technologies. and operating costs of additional pollution control equipment or any penalties imposed Multi-pollutant control legislation has been would adversely affect future results of introduced in Congress and is supported by operations, cash flows and possibly financial the Bush Administration. The legislation would condition unless such costs can be recovered. regulate NOx, S02, Hg and possibly C02 See Note 9 for further discussion. emissions from electric generating plants. AEP and its subsidiaries are advocates of NOx Reductions Affecting AEP, APCo, I&M, OPCo, SWEPCo and TCC comprehensive, multi-pollutant legislation so that compliance planning can be coordinated Federal EPA issued a NOx Rule and adopted and collateral emission reductions maximized. a revised rule (the Section 126 Rule) requiring Optimally, such legislation would establish substantial reductions in NOx emissions in a reasonable emission reduction targets and number of eastern states, including certain compliance timetables based on sound states in which the AEP System s generating science, utilize nationwide cap-and-trade plants are located. The compliance date for programs for achieving compliance as cost- these rules is May 31, 2004. effectively as possible, protect fuel diversity and preserve the reliability of the nation s In 2000, the Texas Commission on electric supply. Management is unable to Environmental Quality (formerly the Texas predict the timing or magnitude of additional Natural Resource Conservation Commission) pollution control laws or regulations. If adopted rules requiring significant reductions additional control technology is required on in NOx emissions from utility sources, AEP System facilities and their costs are not including TCC and SWEPCo. The recoverable from customers through compliance date is May 2003 for TCC and regulated rates or market prices, those costs May 2005 for SWEPCo. could adversely affect future results of operations and cash flows. The following AEP and its subsidiaries are installing a discussions explain existing control efforts, variety of emission control technologies to litigation and other pending matters related to reduce NOx emissions to comply with the environmental issues forAEP companies. applicable state and Federal NOx requirements including selective catalytic Federal EPA Complaint and Notice of reduction (SCR) and non-SCR technologies. Violation AffectingAEP, APCo, CSPCo, I&M The AEP System NOx compliance plan is a dynamic plan that is continually reviewed and and OPCo revised. Current estimates indicate that compliance with the NOx Rule, the Texas Since 1999 AEPSC, APCo, CSPCo, I&M, and Commission on Environmental Quality rule OPCo have been involved in litigation and the Section 126 Rule could result in regarding generating plant emissions under required capital expenditures in the range of the Clean AirAct. Federal EPA, a numberof $1.3 billion to $2 billion of which $843 million states and special interest groups alleged that has been spent through December 31, 2002 AEP System companies modified certain units for the AEP System. at coal fired generating plants in violation of the Clean Air Act over a 20 year period. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability under the Clear Air Act proceedings and unable to predict the timing of resolution of these M-28
The following table shows the estimated results of operations. In those instances compliance cost ranges and amounts spent where AEP or its subsidiaries have been by certain of AEPs registrant subsidiaries named a PRP or defendant, their disposal or through December 31, 2002. recycling activities were in accordance with the then-applicable laws and regulations. Estimated Amounts Unfortunately, Superfund does not recognize Compliance Costs Spent compliance as a defense, but imposes strict (in millions) liability on parties who fall within its broad Company statutory categories. APCo $445 $234 I&M 42-210 5 While the potential liability for each Superfund OPCo 535-864 387 SWEPCo 40 24 site must be evaluated separately, several TCC 5 5 general statements can be made regarding AEP subsidiaries potential future liability. Unless any capital and operating costs of Disposal of materials at a particular site is additional pollution control equipment are often unsubstantiated and the quantity of recovered from customers, they will have an materials deposited at a site was small and adverse effect on future results of operations, often nonhazardous. Although superfund cash flows and possibly financial condition. liability has been interpreted by the courts as See Note 9 for further discussion. joint and several, typically many parties are named as PRPs for each site and several of Superfund and State Remediation Affecting the parties are financially sound enterprises. AEP, APCo, CSPCo, I&M, OPCo, SWEPCo Therefore, our present estimates do not and TCC anticipate material cleanup costs for identified sites for which AEP subsidiaries have been By-products from the generation of electricity declared PRPs. If significant cleanup costs include materials such as ash, slag, sludge, are attributed to AEP or its subsidiaries in the low-level radioactive waste and SNF. Coal future under Superfund, results of operations, combustion by-products, which constitute the cash flows and possibly financial condition overwhelming percentage of these materials, would be adversely affected unless the costs are typically disposed of or treated in captive can be recovered from customers. disposal facilities or are beneficially utilized. In addition, our generating plants and Global Climate Change Affecting AEP and transmission and distribution facilities have all Registrant Subsidiaries used asbestos, PCBs and other hazardous and non-hazardous materials. AEP and its At the Third Conference of the Parties to the subsidiaries are currently incurring costs to United Nations Framework Convention on safely dispose of these substances. Additional Climate Change held in Kyoto, Japan in costs could be incurred to comply with new December 1997, more than 160 countries, laws and regulations if enacted. including the U.S., negotiated a treaty requiring legally-binding reductions in Superfund addresses clean-up of hazardous emissions of greenhouse gases, chiefly C02, substances at disposal sites and authorized which many scientists believe are contributing Federal EPA to administer the clean-up to global climate change. Although the U.S. programs. As of year-end 2002 subsidiaries of signed the Kyoto Protocol on November 12, AEP are named by the Federal EPA as a PRP 1998, the treaty was not submitted to the for five sites. APCo, CSPCo, and OPCo each Senate for its advice and consent by have one PRP site and I&M has two PRP President Clinton. In March 2001, President sites. There are six additional sites for which Bush announced his opposition to the treaty APCo, CSPCo, I&M, KPCo, OPCo and and its U.S. ratification. At the Seventh SWEPCo have received information requests Conference of the Parties in November2001, which could lead to PRP designation. HPL, the parties finalized the rules, procedures and OPCo, SWEPCo and TCC have also been guidelines required to facilitate ratification of named potentially liable at six sites under the protocol. The protocol is expected to state law. Liability has been resolved for a become effective in 2003. AEP does not number of sites with no significant effect on M-29
support the Kyoto Protocol but intends to work TCC, as a partial owner of STP, have a with the Bush Administration and U.S. significant future financial commitment to Congress to develop responsible public policy safely dispose of SNF and decommission and on this issue. Management expects that due decontaminate the plants. The Nuclear to President Bush s opposition to legislation Waste Policy Act of 1982 established federal mandating greenhouse gas emissions responsibility for the permanent off-site controls, any policies developed and disposal of SNF and high-level radioactive implemented in the near future are likely to waste. By law l&M and TCC participate in the encourage voluntary measures to reduce, DOE s SNF disposal program which is avoid or sequester such emissions. AEP has described in Note 9 of the Notes to Financial for many years been a leader in pursuing Statements. Since 1983 I&M has collected voluntary actions to control greenhouse gas $303 million from customers for the disposal emissions. AEP recently expanded its of nuclear fuel consumed at the Cook Plant. commitment in this area by joining the $117 million of these funds have been Chicago Climate Exchange, a pilot deposited in external trust funds to provide for greenhouse gas emission reduction and the future disposal of SNF and $186 million trading program, under which AEP and its has been remitted to the DOE. TCC has subsidiaries are obligated to reduce or offset collected and remitted to the DOE, $53 million 18 million tons of C02 emissions during 2003- for the future disposal of SNF since STP 2006. began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, The acquisition of 4,000 MW of coal-fired collections from customers are to provide the generation in the United Kingdom in DOE with money to build a permanent December 2001 exposes these assets to repository for spent fuel. However, in 1996, potential C02 emission control obligations the DOE notified the companies that it would since the U.K has become a party to the be unable to begin accepting SNF by the Kyoto Protocol. January 1998 deadline required by law. To date DOE has failed to comply with the Control of Mercury Emissions requirements of the NuclearWaste PolicyAct. In December 2000, Federal EPA issued a As a result of DOE's failure to make sufficient regulatory determination listing the electric progress toward a permanent repository or generating sector as a source category under otherwise assume responsibility for SNF, AEP the Clean Air Act for development of on behalf of l&M and STPNOC on behalf of maximum achievable control technology TCC and the other STP owners, along with a standards to control emissions of hazardous number of unaffiliated utilities and states, filed air pollutants, including Hg. Federal EPA is suit in the D.C. Circuit Court requesting, expected to issue proposed regulations in among other things, that the D.C. Circuit 2003 and develop a final rule in 2004. Court order DOE to meet its obligations under Management cannot predict the outcome of the law. The D.C. Circuit Court ordered the these regulatory proceedings, or the costs to parties to proceed with contractual remedies comply with any new standards adopted by but declined to order DOE to begin accepting Federal EPA. The costs associated with SNF for disposal. DOE estimates its planned compliance could be material. However, site for the nuclear waste will not be ready unless any capital and operating costs of until at least 2010. In 1998, AEP and l&M filed additional pollution control equipment are a complaint in the U.S. Court of Federal recovered from customers, they will have an Claims seeking damages in excess of $150 adverse effect on future results of operations, million due to the DOE's partial material cash flows and possibly financial condition. breach of its unconditional contractual deadline to begin disposing of SNF generated Costs for Spent Nuclear Fuel and by the Cook Plant. Similar lawsuits were filed Decommissioning Affecting AEP, I&M and by other utilities. InAugust 2000, in an appeal TCC of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the l&M, as the owner of the Cook Plant, and Federal Circuit held that the delays clause of M-30
the standard contract between utilities and the the trust investments. Studies completed in DOE did not apply to DOE s complete failure 1999 for STP estimate TCC s share of to perform its contract obligations, and that decommissioning cost to be $289 million in the utilities suits against DOE maycontinue in 1999 non-discounted dollars. Amounts court. On January 17,2003, the U.S. Court of collected from customers to decommission Federal Claims ruled in favor of I&M on the STP have been placed in an external trust. At issue of liability. The case continues on the December 31, 2002, the total decommission-issue of damages owed to l&M by the DOE. ing trust fund for TCC s share of STP was $98 As long as the delay in the availability of a million which includes earnings on the trust government approved storage repository for investments. Estimates from the SNF continues, the cost of both temporary decommissioning studies could continue to and permanent storage of SNF and the cost escalate due to the uncertainty in the SNF of decommissioning will continue to increase. disposal program and the length of time that SNF may need to be stored at the plant site. In January 2001, I&M and STPNOC, on I&M and TCC will work with regulators and behalf of STP s joint owners, joined a lawsuit customers to recover the remaining estimated against DOE, filed in November 2000 by costs of decommissioning Cook Plant and unaffiliated utilities, related to DOE s nuclear STP. However, AEP's, I&M s and TCC s waste fund cost recovery settlement with future results of operations, cash flows and PECO Energy Corporation (now Exelon possibly their financial conditions would be Generation Company, LLC). The settlement adversely affected if the cost of SNF disposal adjusted the fees Exelon was required to pay and decommissioning continues to increase to DOE for disposal of SNF. The fee and cannot be recovered. adjustment allowed Exelon to skip payments to the DOE to make up for Exelon s damages Other Environmental Concerns Affecting from DOE s breach of its contract obligation to AEP and all Subsidiaries dispose of SNF from commercial nuclear power plants. The companies believe the AEP and its subsidiaries are exposed to other settlement was unlawful as it would force environmental concerns which are not other utilities (rather than DOE) to considered to be material or potentially compensate Exelon for the damages it had material at this time. Should they become incurred from DOE s breach of contract. In significant or should any new concerns be September 2002, the U.S. Court of Appeals uncovered that are material, they could have for the Eleventh Circuit found that DOE acted a material adverse effect on results of improperly by adopting the fee adjustment operations and possibly financial condition. provision of this settlement, that the fee AEP performs environmental reviews and adjustment provisions of the settlement audits on a regular basis for the purpose of harmed other utilities who pay into the fund identifying, evaluating and addressing and violated the federal nuclear waste environmental concerns and issues. management laws and that the fee adjustment provisions of the settlement were Other Matters null and void. Seasonalitv The cost to decommission nuclear plants is affected by both NRC regulations and the Sale of electric power is generally a seasonal delayed SNF disposal program. Studies business. In many parts of the country, completed in 2000 estimate the cost to demand for power peaks during the hot decommission the Cook Plant ranges from summer months, with market prices also
$783 million to $1,481 million in 2000 non- peaking at that time. In other areas, power discounted dollars. External trust funds have demand peaks during the winter. The pattern been established with amounts collected from of this fluctuation may change depending on customers to decommission the plant. At the nature and location of facilities AEP and December 31, 2002, the total decom- its subsidiaries acquire and the terms of missioning trust fund balance for Cook Plant power sale contracts they enter. In addition, was $618 million which includes earnings on AEP and its subsidiaries have historically sold M-31
I-less power, and consequently earned less Elk City Referendum Affecting AEP and income, when weather conditions are milder. PSO AEP and its subsidiaries expect that unusually mild weather in the future could diminish their In October 2002, the City Commission of Elk results of operations and may impact their City, Oklahoma voted to hold a referendum financial condition. seeking voter approval of a $20.4 million acquisition of PSO s distribution assets within Sustained Earnings Improvement Initiative the city limits. The vote occurred in December 2002 with the referendum being In response to difficult conditions in AEP s defeated. business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide Snohomish Settlement Affecting AEP in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term In February 2003, AEP and the Public Utility earnings growth. Termination benefits District No. I of Snohomish County, expense relating to 1,120 terminated Washington (Snohomish) agreed to terminate employees totaling $75.4 million pre-tax was their long-term contract signed in January recorded in the fourth quarter of 2002. We 2001. Snohomish also agreed to withdraw its determined that the termination of the complaint before the FERC regarding this employees under our SEI initiative did not contract. constitute a curtailment under the provisions Investments Limitations Affecting AEP of SFAS No. 88 "Employers Accounting for Settlements and Curtailments of Defined Our investment, including guarantees of debt, Benefit Pension Plans and for Termination in certain types of activities is limited by Benefits . In addition, certain buildings and PUHCA. SEC authorization under PUHCA corporate aircraft are being sold in an effort to limits us to issuing and selling securities in an reduce ongoing operating expenses. See amount up to 100% of our average quarterly Note 11 for additional information. consolidated retained earnings balance for investment in EWGs and FUCOs. At Non-Core Wholesale Investments December 31, 2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including Additional market deterioration associated guarantees of debt, compared to AEP s limit with AEP s non-core wholesale investments, of $2.8 billion. including AEP s U.K. operations, could have an adverse impact on AEP s future results of SEC rules under PUHCA permitAEP to invest operations and cash flows. Significant long- up to 15% of consolidated capitalization (such term changes in external market conditions amount was $3.2 billion at December 31, could lead to additional write-offs and 2002) in energy-related companies, including potential divestitures of AEP s wholesale marketing and/or trading of electricity, gas and investments, including, but not limited to, other energy commodities. AEP s U.K. operations. M-32
INVESTOR INQUIRIES Investors should direct inquiries to Investor Relations using the toll free number, 1-800-237-2667 or by writing to: Belle Jo Rozsa Managing Director of Investor Relations American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUAL REPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 2003 at no cost to shareholders. Please address requests for copies to: R. Todd Rimmer Director of Financial Reporting American Electric Power Service Corporation 26th Floor I Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK Equiserve Trust Company, N.A. P.O. Box 43069 Providence, RI 02940-3069 Phone Number: 1-800-328-6955 Hearing Impaired Number: TDD: 1-800-952-9245 Website: hftp:1Aww.equiserve.com
Comprehensive Annual Financial Report City of Austin, Texas For the year ended September 30, 2002 Prepared by: Financial and Administrative Services Department John Stephens, CPA Director Barbara Nickle, CPA Controller Members of the Government Finance Officers Association of the United States and Canada
City Council Gus Garcia Mayor Tern expires June 15, 2003 Jackie Goodman Mayor Pro Tem Term expires June 15, 2005 Council Members Raul Alvarez June 15, 2003 Betty Dunkerley June 15, 2005 Daryl Slusher June 15, 2005 Danny Thomas June 15, 2003 Will Wynn June 15, 2003 Toby Hammett Futrell City Manager
CITY OF AUSTIN, TEXAS COMPREHENSIVE ANNUAL FINANCIAL REPORT Year Ended September 30, 2002 TABLE OF CONTENTS Exhibit Page INTRODUCTION Letter of Transmittal City Organization Chart vii Certificate of Achievement viii FINANCIAL SECTION Independent Auditors' Report 3 Management's Discussion and Analysis (unaudited) 3 Basic Financial Statements Government-wide Financial Statements: Statement of Net Assets A-1 16 Statement of Activities A-2 18 Fund Financial Statements: Governmental Funds Balance Sheet I3-1 20 Reconciliation of the Governmental Funds Balance Sheet to the Statement of Net Assets I3-1.1 21 Governmental Funds Statement of Revenues, Expenditures and Changes in Fund Balances I3-2 22 Reconciliation of the Governmental Funds Statement of Revenues, Expenditures and Changes in Fund Balances to the Statement of Activities 3-2.1 23 Proprietary Funds Statement of Net Assets C-1 24 Proprietary Funds Statement of Revenues, Expenses, and Changes in Fund Net Assets C-2 28 Proprietary Funds Statement of Cash Flows C-3 30 Fiduciary Funds Statement of Fiduciary Net Assets D-1 36 Fiduciary Funds Statement of Changes in Fiduciary Net Assets D-2 37 Notes to Basic Financial Statements: Note 1 Summary of Significant Accounting Policies 38 Note 2 Reconciliation of Government-wide and Fund Financial Statements 47 Note 3 Deficits in Fund Balance and Net Assets 49 Note 4 Pooled Investments and Cash 49 Note 5 Investments and Deposits 49 Note 6 Property Taxes 51 Note 7 Capital Assets and Infrastructure 52 Note 8 Retirement Plans 60 Note 9 Selected Revenues 63 Note 10 Debt and Non-Debt Liabilities 64 Note 11 Conduit Debt 82 Note 12 Interfund Balances and Transfers 82 Note 13 Segment Information 83 Note 14 Participation Agreements 84 Note 15 Litigation 85 Note 16 Commitments and Contingencies 86 Note 17 Other Post-Employment Benefits 90 Note 18 Subsequent Events 91 Required Supplementary Information (RSI) (unaudited) General Fund - Schedule of Revenues, Expenditures and Changes in Fund Balances - Budget and Actual-Budget Basis RSI-1 94 Notes to Required Supplementary Information - 95
CITY OF AUSTIN, TEXAS COMPREHENSIVE ANNUAL FINANCIAL REPORT Year Ended September 30, 2002 TABLE OF CONTENTS (continued) Exhibit Page FINANCIAL SECTION, Continued Combining and Fund Financial Statements and Schedules General Fund Schedule of Revenues - Budget and Actual-Budget Basis E-1 97 Schedule of Expenditures - Budget and Actual-Budget Basis E-2 98 Schedule of Transfers - Budget and Actual-Budget Basis E-3 101 Nonmajor Governmental Funds Combining Balance Sheet E-4 104 Combining Statement of Revenues, Expenditures, and Changes in Fund Balances E-5 105 Special Revenue Funds Combining Balance Sheet E-6 107 Combining Statement of Revenues, Expenditures and Changes in Fund Balances E-7 108 Combining Balance Sheet - All Special Revenue Grants E-8 109 Combining Statement of Revenues, Expenditures and Changes in Fund Balances All Special Revenue Grants E-9 110 Combining Schedule of Expenditures - All Special Revenue Grants E-10 111 Other - Combining Balance Sheet E-11 112 Other - Combining Statement of Revenues, Expenditures and Changes in Fund Balances E-1 2 118 Other - Combining Schedule of Revenues, Expenditures and Transfers - Budget and Actual-Budget Basis E-13 124 Debt Service Funds Combining Balance Sheet E-14 130 Combining Statement of Revenues, Expenditures and Changes in Fund Balances E-15 131 Combining Schedule of Revenues, Expenditures and Changes in Fund Balances - Budget and Actual-Budget Basis E-16 132 Capital Projects Funds Balance Sheet E-1 7 134 Statement of Revenues, Expenditures and Changes in Fund Balances E-1 8 135 Combining Balance Sheet E-1 9 136 Combining Statement of Revenues, Expenditures and Changes in Fund Balances E-20 142 Permanent Funds Combining Balance Sheet E-21 150 Combining Statement of Revenues, Expenditures and Changes in Fund Balances E-22 151 Nonmajor Enterprise Funds Combining Statement of Net Assets F-1 154 Combining Statement of Revenues, Expenses and Changes in Fund Net Assets F-2 158 Combining Statement of Cash Flows F-3 160 Internal Service Funds Combining Statements of Net Assets G-1 166 Combining Statement of Revenues, Expenses and Changes in Fund Net Assets G-2 170 Combining Statement of Cash Flows G-3 172
CITY OF AUSTIN, TEXAS COMPREHENSIVE ANNUAL FINANCIAL REPORT Year Ended September 30, 2002 TABLE OF CONTENTS (continued) Exhibit Page FINANCIAL SECTION, Continued Fiduciary Funds Private-Purpose Trust Funds Combining Statement of Fiduciary Net Assets H-1 177 Combining Statement of Changes in Fiduciary Net Assets H-2 178 Agency Funds Combining Statement of Changes in Assets and Liabilities H-3 179 Supplemental Schedules Enterprise Related Grants - Combining Balance Sheet 1-1 181 Enterprise Related Grants - Combining Schedule of Expenditures 1-2 182 Schedule of General Obligation Bonds Authorized and Unissued 1-3 183 Schedule of Revenue Bonds Authorized, Deauthorized and Unissued 1-4 184 STATISTICAL SECTION - UNAUDITED General Governmental Total Expenditures and Expenditures per Capita I 188 General Obligation Net Debt and Net Debt per Capita 2 189 City of Austin Employees per Capita 3 190 Ratio of General Fund Unreserved Ending Balance to General Governmental Annual Expenditures 4 191 Table Page General Governmental Expenditures by Function 1 192 General Governmental Expenditures by Function (Constant Dollars) 2 194 General Fund Revenues and Other Financing Sources by Source 3 195 Assessed Valuation, Estimated Market Value, Tax Rates, Tax Levies, and Tax Collections 4 196 Principal Taxpayers 5 197 Ratio of Net General Bonded Debt to Assessed Value and Net Bonded Debt per Capita 6 198 Ratio of Annual Debt Service Expenditures for General Bonded Debt to Total General Fund Expenditures 7 199 Computation of Legal Debt Margin 8 200 Computation of Direct and Overlapping Debt 9 201 Property Tax Rates and Tax Levies for Direct and Overlapping Governments with Applicable Percentages Over 10% 10 202 City Sales Tax - Tax Levied Effective January 1, 1968 11 203 Electric Fund and Water and Wastewater Fund - Miscellaneous Statistics 12 204 Electric Fund and Water and Wastewater Fund - Five-Year Comparative Operating Schedule 13 205 Electric Fund and Water and Wastewater Fund - Plant Cost and Equity in Utility Systems 14 207 Schedule of Combined Utility Systems Revenue Bond Coverage 15 208 Transfers from Electric Fund and Water and Wastewater Fund to General Fund 16 209 Electric Fund and Water and Wastewater Fund - Statistical Data 17 210 Water and Wastewater Fund - Large Customers 18 211 Airport Enplaned and Deplaned Statistics 19 212 Schedule of Insurance in Force 20 213 Hotel-Motel Occupancy Tax - Tax Levied Effective January 1, 1971 21 215 Vehicle Rental Tax Tax Levied Effective January 1,1999 22 216 Miscellaneous Statistical Data 23 217 Miscellaneous Statistical Data - Economic and Growth Indicators 24 218 Miscellaneous Statistical Data - Employment Characteristics 25 219 Elements of Budget Fund Balance for Selected Operating Funds 26 220
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INTRDUI TION INTRODUCTION
I~Citv5 of Austin Muriiupal Building, 124 West 8th St., P.O. Box 1088, Austin, Texas 78767 March 26, 2003 Honorable Mayor and Council Members City of Austin, Texas Ladies and Gentlemen: We are pleased to submit to you the 2002 Comprehensive Annual Financial Report (CAFR) of the City of Austin, Texas. The report was prepared by the Financial and Administrative Services Department, Controllers Office. The combined financial statements and related notes have been jointly audited by the independent firms of Certified Public Accountants, KPMG LLP, and R. Mendoza, CPA, whose reports are included herein. This audit satisfies Article VII, Section 16 of the City Charter, which requires an annual audit of all accounts of the City by an independent Certified Public Accountant. The Federal awards received by the City directly from Federal agencies or passed through by the State of Texas or other governmental entities during fiscal year 2002 are being audited under the provisions of the Single Audit Act of 1996, as amended, and State awards are being audited under the provisions of the State of Texas Single Audit Circular. The reports will be available in the City s separately issued Single Audit Report. Responsibility for both the accuracy of the presented data and the completeness and fairness of the presentations, including all disclosures, rests with the City. We believe the data, as presented, are accurate in all material respects and are presented in a manner which fairly sets forth the financial position and results of operations of the City. Furthermore, we believe that all disclosures necessary to enable the reader to gain an understanding of the City's financial activity have been included. These financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) for local governments as prescribed by the Governmental Accounting Standards Board (GASB) and the American Institute of Certified Public Accountants (AICPA). This is the first year for the City of Austin to prepare financial statements under Governmental Accounting Standards Board (GASB) Statement No. 34 Basic Financial Statements and Managements Discussion and Analysis for State and Local Governments. Statement No. 34 (GASB 34) was developed to make annual financial reports of state and local governments easier to understand and more useful to those who make decisions using governmental financial information. As a result of the City s implementation of GASB 34, the information in this CAFR differs significantly from previous years. The major changes are, as follows:
- The Comprehensive Annual Financial Report is presented in three sections: Introductory, Financial and Statistical.
The Introductory Section includes this transmittal letter, a list of principal officials and the City s organizational chart. The Financial Section includes the independent auditors report, the managements discussion and analysis, the basic financial statements, required supplementary information and the combining and individual fund financial statements. The Statistical Section includes selected financial and demographics information presented on a multi-year basis.
- New government-wide financial statements are designed to provide readers with a broad overview of the City in a manner similar to a private-sector business. These statements include the statement of net assets and the statement of activities and cover all of the City s activities (except fiduciary activities).
o The statement of net assets reports what the City owns (assets), what it owes (liabilities) and what is left over after assets have been used to satisfy liabilities (net assets). o The statement of activities reports the City s expenses and revenues, as well as other changes in its net assets during the year.
- Other changes associated with the government-wide statements include the following:
o Infrastructure assets are included in the government-wide statement of net assets, and depreciation is included in the statement of activities. Infrastructure assets are roads, bridges, sidewalks, signals and drainage improvements. Financial information on infrastructure assets was not previously required. o The general fixed assets and the general long-term debt account groups no longer exist; the assets and liabilities previously reported in these account groups are now reported in the government-wide statements. i
A.
- Fund financial statements report the finances of fund groups within the City s reporting entity its governmental, proprietary and fiduciary funds. Reconciliations describe the adjustments necessary to move from the fund financial statements to the government-wide financial statements. The reconciliations are included because the two types of statements measure the City s finances differently. The fund financial statements are similar to statements presented in prior years.
- Fund financial statements focus on major funds, as defined by GASB 34. The major funds of the City are the General Fund, Electric, Water and Wastewater, and Airport funds. Other funds are grouped together and reported as nonmajor funds.
- Funds previously reported as expendable and nonexpendable trust funds have been reclassified as special revenue funds, agency funds or permanent funds. Permanent funds are a new fund-type created to report resources which legally permit earnings, and not principal, to be used to support the City s programs.
- Managements Discussion & Analysis (MD&A) is required supplementary information, and provides information and analysis that users need to interpret the basic financial statements. This letter of transmittal complements the MD&A and should be read in conjunction with it. The MD&A can be found immediately following the independent auditors report.
REPORTING ENTITY This CAFR includes the financial activities of the primary government and its component units. The City provides a full range of services, including general government, public safety, transportation, planning and sustainability, public health, public recreation and culture, urban growth management, electric, water and wastewater, airport and other enterprise services. In addition, the City has blended with its financial statements those of the separate legal entities, the Austin Housing Finance Corporation, whose activities are reported in the Housing Assistance Fund, and the Austin Industrial Development Corporation, whose activities are included in the Austin Industrial Development Corporation Fund. AUSTIN S GOVERNMENT, ECONOMY AND OUTLOOK The City of Austin, chartered in 1839, has a Council-Manager form of government with a Mayor and six Councilmembers. The Mayor and Councilmembers are elected at large for three-year staggered terms, with a maximum of two consecutive terms. The City Manager, appointed by the City Council, is responsible to them for the management of all City employees and the administration of all City affairs. This was a year of transition for City management with the appointment of Toby Hammett Futrell as City Manager, following the departure of long-term City Manager Jesus Garza. The City is the cultural and creative hub of the Central Texas area, a metropolitan region with 670,000 residents. In recent years, both the population and economy of Austin have grown extraordinarily. The population increased 40 percent in the last decade, and the per capita income rose from $18,000 to $32,000 annually. Austin is frequently recognized as a great place to live andlor work, with one of the most recent commendations in Money magazine's 16th Annual "Ten Best Places to Live in America," where Austin is ranked eighth. Austin has long attracted a variety of people, and the reasons that draw people to the City are varied. The area has a natural beauty and a first-rate parks department that administers a number of public outdoor recreational facilities, including neighborhood parks, greenbelts, athletic fields, golf courses, tennis courts, a veloway for bicyclists and in-line skaters, miles of hike and bike trails and striped bike lanes, a youth entertainment complex and swimming pools. Residents of Austin enjoy many outdoor events, including art, music, and food and wine festivals; races and bicycle rides; and the nightly flights of the world s largest urban bat colony. Indoor events vary from music to museums to ice hockey, art galleries, an opera facility and a wide variety of restaurants and clubs. Long recognized as the live music capital of the world," Austin boasts more than100 live music venues, and is home to the annual South by Southwest (SXSW) music and film festivals each spring. The educational opportunities in Austin have long drawn people to the city. Among U.S. cities with a population over 250,000, Austin is one of the most highly educated cities, with more than 30% of its adults having a college degree and over 88% of the workforce having some college education. With its seven institutions of higher learning and more than 94,000 students, education is a significant aspect of life in the Austin area. The University of Texas at Austin (UT), the largest public university in the nation, is known as a world-class center of education and research. During the 1990s, over 280,000 jobs were created in Austin; unemployment dropped to less than 2 percent in 2000. Since then, Austin and the Central Texas area have been hit hard by the technology slump. Unemployment in the area has increased sharply over the last two years. Austin s unemployment rate averaged near 6 percent during 2002, with almost 24,000 people unemployed. Statewide unemployment was also almost 6 percent. ii
Layoffs and the nationwide slump in tourism have negatively impacted both sales tax and hotel tax revenues. Sales tax revenue for the City declined by 6 percent from the prior year and hotel-motel taxes declined by 20 percent. Early 2003 collections show a decline in sales tax, and an increase in hotel tax. Property taxes for 2003 may be negatively impacted by lawsuits filed against the appraisal district; the suits challenge the appraisal district s property valuations for many businesses. If the challenges are successful, they could result in decreased tax revenue next year for the local taxing jurisdictions, including the City. These financial statements include the impact of estimated refunds of 2002 taxes. The drop in the hotel tax collections is consistent with the nationwide decline in travel and tourism. The decline in travel has impacted both the City s airport and convention revenues. The airport has experienced a decline inboth passenger and cargo traffic. For electric and water and wastewater activities, mild weather conditions resulted in lower than anticipated revenues. With these experiences, City management implemented savings efforts early in 2002, and successfully reduced expenditures during the year, with a focus on reducing administrative costs. The savings efforts concentrated on holding vacant positions open and on identifying savings opportunities. As part of the 2003 budget, over 300 vacant positions were cut from the budget. Early economic forecasts indicated 2003 to be a transition year, with the Austin area expected to experience a modest recovery. Early 2003 indicators however show a delay in the recovery. Moving into 2003, sales taxes continued to drop. City management is taking steps to reduce expenditures for 2003 by implementing a hiring freeze and developing plans to achieve operational efficiencies. For the future, Austin s strengths continue to be the ones that lead to growth in the recent past: a highly capable workforce, innovation and entrepreneurship, clusters in knowledge industries, the presence of a world-class research university and several other institutions of higher learning, strong community assets and a superior quality of life. Austin has concentrated economic activity in four major areas: technology-related manufacturing and research; entertainment, including film, digital entertainment and live music; information, especially publishing and software; and professional services. MAJOR INITIATIVES AND ACHIEVEMENTS The City has a number of significant initiatives underway or recently completed, as described below. These initiatives should have a positive effect on the City s economic health and services to residents and businesses. Health and Safety Projects Brackenridge Hospital is operated by the Daughters of Charity under a lease agreement with the City. The City is constructing and will operate a hospital on the fifth floor of Brackenridge Hospital. The new hospital will maintain access for anyone in need of reproductive health care services; maintain seamless delivery of services; and maintain the high quality of care available at Brackenridge Hospital. The facility is expected to open in July 2003. The City, Travis County and local leaders are developing a plan for a hospital/health care district for Austin/Travis County. Such a district would allow for the creation of a dedicated funding source for the provision of health care and trauma services to all residents in Austin and Travis County. Construction continues on a combined emergency center that is part of a major regional upgrade of all emergency communications systems and facilities. The center replaces the City of Austin and Travis County 9-1-1 Communications Centers and provides critical upgrades to the current emergency service systems. The center will also include the Austin and Travis County Regional Emergency Operations Center and integrates emergency services with a new, regional Transportation Management Center for the Texas Department of Transportation. Convention and Cultural Projects The Convention Center expanded facilities during 2002, with three additions: the Austin Convention Center expansion that doubled the size of the Center; the Palmer Events Center that is a new facility with 131,000 square feet, including 70,000 square feet of exhibit space; and the Palmer Events Parking Garage that Is a four-story parking structure. The Events Center and parking garage were funded by a 5 percent increase in car rental tax. The City continues with building a new City Hall and Public Plaza, which will be Austin s newest landmarks. The City Hall will overlook lovely Town Lake. New state legislation in 2001 allowed for use of the Construction Manager At-Risk model, in which the construction manager selection is based on qualifications and experience, and is not limited to the low-bid method of selection. The City has selected Hensel Phelps Construction Co. of Austin as the construction manager for the City Hall. Construction of the City Hall parking garage was completed in 2002. iii
Economic Development and Transportation Projects A vital, on-going project is the redevelopment of the former Robert Mueller Municipal Airport (RMMA) site. The 709-acre site is envisioned as a transit-oriented community, including a town square, a mixed-use district, an employment center, a variety of residential uses, and possible site of a new hospital. The City selected Catellus Development Corporation as the developer for this long-term project and is currently negotiating the elements of the development agreement for the property. The City is continuing work on transportation projects approved by the voters in 2000. Projects include State highway (SH) projects such as improvements to SH 183, which will improve access to Austin-Bergstrom International Airport, extension of Loop 1 North and construction of an east-west highway SH 45N in the northern portion of Travis County and SH 130, which will provide an alternative to IH 35 to the east of the City. Projects also include improved transportation options for pedestrians and bicyclists. Utility Projects Austin Energy, the City s electric utility, continues to prepare for possible deregulation. Deregulation allows Texas residents and businesses served by utilities participating in deregulation to choose the supplier from which they purchase their electricity. The local electric utility continues to deliver the electricity. Deregulation began in Texas on January 1, 2002 for all private electric utilities. These utilities, owned by stockholders, are called investor-owned utilities (lOUs). Electric cooperatives (Co-ops) and city-owned electric utilities (called municipally owned utilities or MOUs) such as Austin Energy can participate, or 'opt-in, by a vote of their board or City Council. Once the City Council votes to participate in deregulation, it cannot later withdraw. The City has not 'opted-in, but does continue to prepare for that possibility. A key step in preparation for deregulation was to begin moving from issuing combined utility debt (combined electric and water and wastewater) to issuing debt specific to the electric utility. To proceed towards that goal, Austin Energy issued $247.6 million Electric Utility System revenue refunding bonds and refunded $281.9 million Combined Utility System revenue bonds during 2002. During 2002, the Water and Wastewater Utility enhanced security for the water supply and distribution systems. It also launched a program in 2002 to stop sanitary sewer system overflows by the end of 2007. The Utility also began planning for treatment capacity expansions, including a future plant in 2029. The Utility reduced its total debt liability by issuing refunding bonds during the year. In addition, the Utility obtained bondholders consent to replace a debt reserve fund with a surety bond; this action will result in releasing cash reserves that can be used to defease outstanding bonds. Status of city services Since 1997, the City has conducted two surveys: Citizen Satisfaction and Survey of City Priorities. Highlights of the most recent surveys are, as follows:
- 97% of citizens express satisfaction with the services provided by Fire and EMS
- 91% of citizens are satisfied with 911 services
- 85% of citizens are satisfied with the services and programs provided by Parks and Recreation Department
- 87% of citizens are satisfied with the recycling services provided and 81% are satisfied with the garbage pickup
- Based on the most current information, Austin has the lowest infant mortality rate of the major cities in Texas
- 75% of citizens are satisfied with the health care available inAustin for low-income individuals
- Austin has the lowest property~tax rate of the five major Texas cities.
OTHER Internal Controls and Budgetary Control City management is responsible for establishing, implementing and maintaining a framework of internal controls designed to ensure that City assets are protected from loss, theft or misuse, and to ensure that adequate accounting data is compiled to allow for the preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP). The system of internal control is designed to provide reasonable, but not absolute, assurance that these objectives are met. The concept of reasonable assurance recognizes that: 1) the cost of control should not exceed the benefits likely to be derived; and 2) the evaluation of costs and benefits requires estimates and judgments by management. All internal control evaluations occur within this framework and are believed to adequately safeguard assets and provide reasonable assurance of proper recording of financial transactions. The City employs a computerized financial accounting system that includes a system of internal accounting controls. The Financial and Administrative Services Department is responsible for providing all centralized City financial services including financial accounting, reporting and budgeting, payroll and accounts payable disbursement functions, cash and investment management, debt management, and purchasing and contract administration. The Director of Financial Services, appointed by the City Manager, supervises the department's operations. iv
The objective of budgetary controls is to ensure compliance with legal provisions in the annual appropriated budget approved by the City Council. The annual operating budget, or financial plan, is proposed by the City Manager and enacted by the City Council after public discussion. Subsequent intradepartmental budget transfers must be approved by the City Manager. Interdepartmental transfers and any increase or decrease in total appropriations must be approved by the City Council. Management control for the operating budget is maintained at the fund and department level. Primary responsibility for fiscal analysis of budget to actual expense or revenue and overall program fiscal standing rests with the department operating the program. As demonstrated by the statements and schedules included in the Citys 2002 Comprehensive Annual Financial Report, the City continues to meet its responsibility for sound financial management Cash Management The Citys investment policy is to minimize credit and market risk while maintaining a competitive portfolio yield. Cash balances of all City funds are invested in consideration of five factors: safety, term, liquidity, market exposure and rate of return. Cash balances of most funds, except the debt service and revenue bond retirement reserve, are pooled for investment purposes. These investments are made in accordance with the Texas Public Funds Investment Act and the City of Austin Investment Policy. During 2002, the City's cash resources were primarily invested in U.S. Treasury and Agency issues. The average yield on pooled investments during the year was 3.3 percent, and the weighted average maturity of the investments was 331 days. Risk Management The City maintains three internal service funds to account for its risk of loss associated with torts and employee and workers compensation benefits. The City continues to be self-insured for liabilities for most health benefits, third-party claims, and workers compensation. The City purchases commercial insurance for coverage for property loss or damage, commercial crime, fidelity bond and airport operations. In addition, the City purchases a broad range of insurance coverage for contractors working at selected capital improvement project sites. The City does not participate in a risk pool. Liabilities are reported when it is probable that a loss has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Liabilities include an amount for claims that have been incurred but not reported (IBNR). Claim liabilities for the Employee Benefits Fund are calculated considering recent claim settlement trends; liabilities for the Liability Reserve and Workers Compensation funds are calculated based on outstanding claims. CERTIFICATE OF ACHIEVEMENT The Government Finance Officers Association of the United States and Canada (GFOA) awarded a Certificate of Achievement for Excellence in Financial Reporting to the City for its 2001 Comprehensive Annual Financial Report (CAFR). This is the tenth consecutive year that the City has achieved this prestigious award. A Certificate of Achievement is valid for a period of one year only. City management believes that this 2002 CAFR conforms to the Certificate of Achievement Program requirements, and we are submitting it to GFOA for its review. ACKNOWLEDGMENTS The preparation of this report on a timely basis could not have been accomplished without the dedicated services of a highly qualified staff. The City of Austin has such a staff in the Controller's Office of the Financial and Administrative Services Department. We would like to express our appreciation to all the staff of the Controller's Office who assisted in and contributed to the preparation of this report. Other departments and offices of the City have also contributed directly or indirectly to the preparation of this report. In particular, the Budget Office of the Financial and Administrative Services Department and the Office of the City Auditor have been instrumental in ensuring that good financial management practices are maintained, and their cooperation and continued assistance is appreciated. We also acknowledge the efforts of the City departments in following good financial management practices and in providing information and assistance during the preparation of the report. v
We acknowledge the thorough, professional and timely manner in which our independent auditors, KPMG LLP and R. Mendoza, CPA, conducted the audit Finally, we acknowledge the Mayor and Council Members who have consistently supported the City's goal of excellence in all aspects of financial management Their support is greatly appreciated. Toby mmett Futrell City Manager Jo* Stephens, CPA Di ctor, Financial and Administrative Services Department vi
City of Austin, Texas ORGANIZATIONAL CHART i Boards and I unicipal Court IC lr I ,LE Commissions vii
Certificate of Achievement for Excellence The Government Finance Officers in Financial Association of the United States and Canada (GFOA) awarded a Certificate of Achievement for Reporting Excellence in Financial Reporting to the City of Austin, Texas for its Presented to Comprehensive Annual Financial Report for the Fiscal Year Ended September 30, 2001. City of Austin, In order to be awarded a Certificate of Achievement, a Texas governmental unit must publish an easily readable and efficiently For its Comprehensive Annual organized Comprehensive Annual Financial Report Financial Report, whose contents for the Fiscal Year Ended conform to program standards. Such reports must satisfy both September 30, 2001 generally accepted accounting A Certificate of Achievement for Excellence in Financial principles and applicable legal Reporting is presented by the Government Finance Officers requirements. A Certificate of Association of the United States and Canada to Achievement is valid for a period government units and public employee retirement of one year only. City systems whose comprehensive annual financial management believes that this reports (CAFRs) achieve the highest 2002 CAFR conforms to the standards in government accounting Certificate of Achievement and financial reporting. Program requirements, and we are submitting it to GFOA for their review. President Executive Director Viii
f~INANCIAL SIJJON FINANCIAL SECTION
R. Mendoza g o at&? Company, PC 111 Congress Avenue i PublicAccountants Suite 1100 2211 South I. H. 35, Suite 410 Austia TX 78701 Austin, TX 78741 INDEPENDENT AUDITORS' REPORT The Honorable Mayor and Members of the City Council. City of Austin, Texas: We have audited the accompanying financial statements of the governmental activites, the business-type activities, each major fund, and the aggregate remaining fund information of the City of Austin, Texas ('Cty'), as of and for the year ended September 30, 2002, which collectively comprise the City's basic financial statements as listed in the table of contents under
'Basic Financial Statements'. These financial statements are the responsibility of the City's management. Our responsibility is to express opinions on these financial statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinions. In our opinion, the financial statements referred to above present fairly, in all material respects, the respective financial position of the governmental activities, the business-type activities, each major fund, and the aggregate remaining fund Information of the City, as of September 30, 2002, and the respective changes in financial position and cash flows, where applicable, thereof for the year then ended in conformity with accounting principles generally accepted In the United States of America. As described in Note lb, the City has implemented a new financial reporting model, as required by Governmental Accounting Standards Board ('GASB") Statement No. 34, Basic Financial Statements - and Management's Discussion and Analysis - for State and Local Governments, GASB Statement No. 37, Basic Financial Statements - and Management's Discussion and Analysis - for State and Local Governments: Omnibus, GASB Statement No. 38, Certain Financial Statement Note Disclosures, and GASB Interpretation No. 6, Recognition and Measurement of Certain Liabilities and Expenditures In Governmental Fund Financial Statements, as of October 1, 2001. The Management's Discussion and Analysis on pages 3 through 14 and the General Fund Schedule of Revenues, Expenditures and Changes in Fund Balances - Budget and Actual - Budget Basis on pages 94 through 95 are not a required part of the basic financial statements but are supplementary Information required by accounting principles generally accepted in the United States of America. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on It. Our audit was conducted for the purpose of forming opinions on the financial statements that collectively comprise the Ciys basic financial statements. The accompanying introduction, combining and fund financial statements and schedules, supplemental schedules, and statistical section are presented for purposes of additional analysis and are not a required part of the basic financial statements. The combining and fund financial statements and schedules, and supplemental schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, are fairly stated in all material respects in relation to the basic financial statements taken as a whole.' The introduction and statistical section have not been subjected to the auditing procedures applied in the audit of the basic financial statements and, accordingly, we express no opinion on them. Austin, Texas January 31, 2003 Eu I ICPMGUP KPMGUa US Uhited
*mot&betof KMG kwrf-A, S .,-
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Management s Discussion and Analysis City of Austin, Texas September 30, 2002 This section of the City of Austin s (the City) Comprehensive Annual Financial Report presents a narrative overview and analysis of the financial activities of the City for the fiscal year ended September 30, 2002. We encourage readers to consider the information presented here in conjunction with additional information that we have furnished in our letter of transmittal. This is the first year that the City has presented its financial statements under the new reporting model required by the Governmental Accounting Standards Board Statement No. 34 (GASB 34), Basic Financial Statements- and Managements Discussion and Analysis (MD&A) for State and Local Governments, as well as the related statements No. 37 and 38 and GASB Interpretation No. 6, Recognition and Measurement of Certain Liabilities and Expenditures in Governmental Fund FinancialStatements. Because the reporting model changes significantly both the recording and presentation of financial data, the City has not restated prior fiscal years for the purpose of providing comparative information for the MD&A. The City will present comparative data in future years. FINANCIAL HIGHLIGHTS The assets of the City exceeded its liabilities at the close of the most recent fiscal year by $3.4 billion (net assets). Of this amount $865 million (unrestricted net assets) may be used to meet the governments ongoing obligations to citizens and creditors. The governments total net assets increased by $125 million during the fiscal year. As of September 30, 2002, the Citys governmental activities reported combined net asset balances of $1.2 billion. Approximately 9% of this total amount, or $107 million, represents unrestricted net assets available for spending at the government s discretion. At the close of the current fiscal year, unreserved fund balance for the General Fund was $88 million or 20% of total General Fund expenditures of $430 million. The City s total long-term obligations increased $305 million during the current fiscal year. Govemmental debt increased $231 million and business-type debt increased $74 million; business-type debt is self-supporting, and does not rely on tax revenues for repayment. The key factors in this increase included issuance of new debt, which was partially offset by payment or refunding of existing debt. OVERVIEW OF THE FINANCIAL STATEMENTS This discussion and analysis are intended to serve as an introduction to the Citys basic financial statements, which consist of three components:
- government-wide financial statements,
- fund financial statements and
- notes to the financial statements.
This report also contains other supplementary information in addition to the basic financial statement, including information on individual funds. a - Government-wide Financial Statements The govemment-wide financial statements are designed to provide readers with a broad overview of the Citys finances, in a manner comparable to a private-sector business. The two government-wide financial statements are, as follows:
- The statement of net assets presents information on all of the City s assets and liabilities, with the difference between the two reported as net assets. Over time, increases or decreases in net assets may serve as a useful indicator of whether or not the financial position of the City is improving or deteriorating.
- The statement of activities presents information showing how the City s net assets changed during the most recent fiscal year. All changes in net assets are reported as soon as the underlying event giving rise to the change occurs, regardless of the timing of related cash flows. Thus, revenues and expenses are reported inthis statement for some items that will only result in cash flows in future fiscal periods, such as revenues pertaining to uncollected taxes and expenses pertaining to future general obligation debt payments. The statement includes the annual depreciation for infrastructure and governmental assets.
3
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) OVERVIEW OF THE FINANCIAL STATEMENTS, continued Both of the govemment-wide financial statements distinguish functions of the City that are principally supported by taxes and intergovernmental revenues (governmental activities) from other functions that are intended to recover all or a significant portion of their costs through user fees and charges (business-type activities). The governmental activities of the City include general government; public safety; transportation, planning and sustainability; public health; public recreation and culture and urban growth management The business-type activities of the City include electric utility, water and wastewater utility, airport, convention and others. The government-wide financial statements include the City as well as blended component units, the Austin Housing Finance Corporation (AHFC) and the Austin Industrial Development Corporation (AIDC). The operations of AHFC and AIDC are included within the governmental activities of the government-wide financial statements. AHFC is reported as the Housing Assistance Fund. Although legally separate from the City, these component units are blended with the City because of their governance or financial relationships to the City. b - Fund Financial Statements The fund financial statements are designed to report information about groupings of related accounts which are used to maintain control over resources that have been segregated for specific activities or objectives. The City, like other state and local governments, uses fund accounting to ensure and demonstrate compliance with finance-related legal requirements. All of the funds of the City can be divided into the following three categories: governmental, proprietary and fiduciary funds. Within the governmental and proprietary categories, the emphasis is on the major funds. Governmental funds. Governmental funds are used to account for essentially the same functions reported as governmental activities in the government-wide financial statements. Most of the City s basic services are reported in governmental funds, which focus on how cash and other financial assets can readily be converted to available resources and on the available balances left at the year-end. This information may be useful in determining what financial resources are available in the near future to finance the City s programs. Other funds are referred to as nonmajor funds and are presented as summary data. Because the focus of governmental funds is narrower than that of the government-wide financial statements, it is useful to compare the information presented for governmental funds with similar information presented in the government-wide statements. In addition to the governmental fund balance sheet and statement of revenues, expenditures and changes In fund balance separate statements are provided that reconcile between the government-wide and fund level statements. The City s General Fund is considered a major fund, and information is presented separately in the governmental fund balance sheet and statement of revenues, expenditures and changes in fund balances. In addition, the City maintains several individual governmental funds organized according to their type (special revenue, debt service, capital projects and permanent funds). Data from these governmental funds are combined into a single column labeled nonmajor governmental funds. Individual fund data for the funds are provided in the form of combining statements in the supplementary section of this report. Proprietary funds. Proprietary funds are generally used to account for services for which the City charges customers either outside customers or internal units or departments of the City. Proprietary fund statements provide the same type of information as shown in the government-wide financial statements, only in more detail. The City maintains the following two types of proprietary funds:
- Enterprise funds are used to report the same functions presented as business-type activities in the government-wide financial statements. The City uses enterprise funds to account for the operations of the City s three major funds, Electric, Water and Wastewater and Austin-Bergstrom International Airport (Airport), as well as the nonmajor enterprise funds.
- Internal Service funds are used to report activities that provide supplies and services for many City programs and activities.
The City uses internal service funds to account for Capital Projects Management, Employee Benefits, Fleet Maintenance, Information Systems, Liability Reserve, Support Services, Wireless Communication and Workers Compensation. Because these services benefit governmental operations more than business-type functions, they have been included within governmental activities in the govemment-wide financial statements. The nonmajor enterprise funds and the internal service funds are combined into two aggregated presentations in the proprietary fund financial statements. Individual fund data for the funds are provided in the form of combining statements in the supplementary section of this report. 4
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) OVERVIEW OF THE FINANCIAL STATEMENTS, continued Fiduciary funds. Fiduciary funds are used to account for resources held for the benefit of parties outside the City. Since the resources of fiduciary funds are not available to support the City s own programs, they are not reflected in the government-wide financial statements. The accounting used for fiduciary funds is much like that used for proprietary funds. Comparison of Government-wide and Fund Financial Components. The following chart compares how the City s funds are included in the government-wide and fund financial statements: Government-Fund Types I Other wide Fund Financials General Fund Governmental Governmental Special revenue funds Govemmental Governmental - Nonmajor Debt service funds Governmental Govemmental - Nonmajor Capital project funds Govemmental Governmental - Nonmajor Permanent funds Govem mental Govemmental - Nonmajor Internal service funds Governmental Proprietary Assets previously reported in General Fixed Asset Group Govemmental Exciuded Infrastructure assets Govemmental Exciuded Liabilities previously reported in General Long-Term Debt Group Govemmental Excluded Electric Business-type Proprietary Water and wastewater Business-type Proprietary Airport Business-type Proprietary Other enterprise funds Business-type Proprietary -Nonmajor Fiduciary funds Excluded Fiduciary Basis of Reporting - The government-wide statements and fund-level proprietary statements are reported using the flow of economic resources measurement focus and on full accrual basis of accounting. The governmental fund financial statements are reported using the current financial resources measurement focus and the modified accrual basis of accounting. c - Notes to the Financial Statements The notes to the financial statements provide additional information that is essential to a full understanding of the data provided in the government-wide and fund financial statements. d - Other Information The section Required Supplementary Information (RSI) immediately follows the basic financial statements section of this report. The City adopts an annual appropriated budget for the General Fund. The RSI provides a comparison to budget and demonstrates budgetary compliance. Following the RSI are other statements and schedules, including the combining statements for nonmajor governmental and enterprise funds, internal service funds and fiduciary funds. 5
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT-WIDE STATEMENTS a - Net Assets Combined net assets of the City were, as follows (in thousands): Net Assets September 30,2002 (in thousands) Governmental Business-Type Ctivities Actvtes Total Current and other assets $ 576,628 Z006,640 2,583,268 Capital assets 1,688,064 4,774,427 6,46Z491 Total assets 2,264,692 6,781,067 9,045,759 Other liabilities 185,118 438,202 623,320 Long-term liabilities 83Z137 4,186,161 5,018,298 Total liabilities 1,017,255 4,624,363 5,641,618 Net assets: Invested in capital assets, net of related debt 1,111,491 1,196,098 2,307,589 Restricted 28,492 20Z651 231,143 Unrestricted 107,454 757,955 865,409 Total net assets $ 1,247,437 Z156,704 3,404,141 As noted earlier, net assets may serve as a useful indicator of a governments financial position. For the City, assets exceeded liabilities by $3.4 billion at the close of the current fiscal year. However, the largest portion of the City s net assets are restricted as to use or are invested in capital assets (e.g. land, building, and equipment - 68%), less any related outstanding debt used to acquire those assets. The City uses these capital assets to provide services to citizens; consequently, these assets are not available for future spending. Although the Citys investment in its capital assets is reported net of related debt, it should be noted that the resources needed to repay this debt must be provided from other sources, since the capital assets themselves cannot be liquidated for these liabilities. An additional portion of the Citys net assets, $231 million (7%), represents resources that are subject to external restrictions on how they may be used. The remaining balance of unrestricted net assets, $865 million (25%), may be used to meet the government s ongoing obligations to citizens and creditors. At the end of the current fiscal year, the City is able to report positive balances in all three categories of net assets for the government as a whole, as well as for the business-type activities. 6
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT-WIDE STATEMENTS, continued b - Changes in Net Assets Total net assets of the City increased by $124.5 million in the current year. Governmental net assets increased $42.5 million, which is attributable primarily to taxes and transfers from business-type activities. The business-type net assets increased by $82 million, with revenues and transfers exceeding expenses; revenues are produced primarily by the sale of electric utility services. Changes InNet Assets September 30, 2002 (Inthousands) Business-Governmental Type Activities Activities Total Program revenues: Chargesforservices $ 84,349 1,174,755 1,259,104 Operating grants and contributions 53,374 - 53,374 Capital grants and contributions 1,203 43,537 44,740 General revenues: Property tax 224,396 - 224,396 Sales tax 115,441 - 115,441 Franchise fees and gross receipts tax 62,576 - 62,576 Grants and contributions not restricted specific programs 19,137 - 19,137 Interest and other 23,746 58,180 81,926 Total revenues 584,222 1,276,472 1,860,694 Program expenses: General government 75,941 - 75,941 Public safety 279,533 - 279,533 Transportation, planning and sustainability 15,694 - 15,694 Public health 75,033 - 75,033 Public recreation and culture 71,863 - 71,863 Urban grLoth management 54,287 - 54,287 Unallocated depreciation expense - infrastructure 34,074 - 34,074 Interest on debt 35,771 - 35,771 Electric - 610,374 610,374 Water and Wastewater - 251,171 251,171 Airport - 76,546 76,546 Convention - 36,344 36,344 Other - 115,518 115,518 Total expenses 642,196 1,089,953 1,732,149 Excess before special items and transfers (57,974) 186,519 128,545 Special Items - purchased land lease rights (4,000) - (4,000) Transfers 104,519 (104,519) - Increase in net assets 42,545 82,000 124,545 Net assets, October 1 1,204,892 2,074,704 3,279,596 Net assets, September30 $ 1,247,437 2,156,704 3,404,141 7
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT-WIDE STATEMENTS. continued c - Program Revenues and Expenses Governmental Activities Governmental activities increased the City s net assets by $42.5 million, thereby accounting for 34% of growth in the net assets of the City. Key factors of this increase are as follows:
- The City s property tax revenue increased by $25.6 million, primarily as a result of increasing assessed value; the City s tax rate was reduced $.0066 per $100 assessed value.
- Sales and other taxes decreased during the year, with sales tax decreasing more than 6%.
- Transfers in from enterprise funds increased from the prior year.
- The most significant increase in expenses was in the public safety area, with costs related to post-September II activities and implementation of police pay and benefit changes.
The chart below illustrates the City s governmental expense and revenues by function: general government; public safety; transportation, planning and sustainability; public health; public recreation and culture; urban growth management; unallocated depreciation expense and interest on debt. Government-wide Program Expenses and Revenues Governmental Activities (in thousands) 300,000 _ 275,000 _ -U *s Expense 250,000 _ o Program Revenue 225,000 -_- 200,000 175,000 150,000 125,000 100,000 75,000 50,000 U In U _ 25,000 I171 Wi.1 I 17 General government Public safety Transportation, planning and Public health 71 17 u-Public recreation and Urban growth management Unallocated depredation Interest on debt sustainability culture expense 8
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT-WIDE STATEMENTS, continued General revenues such as property taxes, sales taxes and franchise fees are not shown by program, but are used to support program activities citywide. For governmental activities, without regard to program, property taxes are the largest source of revenue, followed by sales taxes and charges for services. Government-wide Revenues by Source - Governmental Activities Franchise fees Charges for Other Services and gross 8% receipts tax 14% 11% Operating Grants and Contributions Sales tax K i 9% 20% Property tax 38% d Program Revenues and Expenses - Business-type activities Business-type activities increased the City s net assets by $82 million, accounting for 66% of the total growth in the City s net assets. Net program expenses and revenues are, as follows:
- Electric net assets increased $138 million, primarily from charges for services. Both revenues and expenses decreased from the prior year.
- Water and Wastewater net assets increased $8 million, due primarily to cost containment actions by the utility.
- Airport net assets increased $5 million, a result of cost-containment measures put in place following September 11.
- Convention net assets decreased $26 million, due primarily to reduced interest income and hotel tax transfers.
As shown in the following chart, the Electric utility, with operating expenses of $610 million, is the Citys largest business-type activity, followed by the Water and Wastewater utility ($251 million), the Airport ($77 million) and Convention Center ($36 million). For the fiscal year, operating revenues exceeded operating expenses for all business-type activities, except these nonmajor funds: Parks and Recreation activities such as recreation and tennis, Primary Care and Solid Waste Services. 9
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT-WIDE STATEMENTS, continued Government-wide Expenses and Program Revenues - Business-type Activities (Excludes General Revenues and Transfers) (in thousands) 800,000 700,000 600,000 500,000 400,000 300,000 200,000 100,000 Electric Water/Wastewater Airport Convention Other For all business-type activities, charges for services provide the largest percentage of revenues (92%), followed by interest and other revenues (5%) and capital grants and contributions (3%). Government-wide Revenue by Source Business-type Activities Capital hterest and Grants and other Contributions 5% 3% Charges for Services 92% 10
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT S FUND LEVEL STATEMENTS In comparison to the government-wide statements, the fund-level statements focus on the key funds of the City. The City uses fund accounting to ensure and demonstrate compliance with finance-related legal requirements. a - Governmental funds The City reports the following types governmental funds: the General Fund, special revenue funds, debt service funds, capital project funds and permanent funds. The focus of the City s governmental funds is to provide information on near-term inflows, outflows and balances of resources that are available for spending. Such information is useful in assessing the City s financing requirements. In particular, unreserved fund balance may serve as a useful measure of a governments net resources available for spending at the end of the fiscal year. The General Fund is the chief operating fund of the City. At the end of the current fiscal year, the unreserved fund balance of the General Fund was $88 million, while total fund balance was $94 million. As a measure of the General Funds liquidity, it may be useful to compare both unreserved fund balance and total fund balance to total fund expenditures. Unreserved fund balance represents 20% of total General Fund expenditures of $430 million, and total fund balance represents 22% of expenditures. Fund balance amounts may also be designated by City Council for specified uses for the future; the unreserved and undesignated fund balance is $36 million. The General Fund fund balance increased by $43 million during the fiscal year; undesignated fund balance increased by $12 million. Key factors in this increase were, as follows:
* $2 million increase in revenues, with the primary increase in property taxes
* $51 million increase in transfers in,with the primary increase from nonmajor enterprise funds.
* $34 million increase in expenditures, primarily in public safety.
* $21 million decrease in transfers out, with decreases primarily for Special Revenue and Capital Project funds.
Fund balance of the special revenue funds decreased $6 million in FY 2002, with the most significant impacts in the following funds (in millions): transferred Federally Qualified Health Center to the enterprise funds ($2); reduced tourism-related revenues or transfers of tourism-related revenues: PARD Cultural Projects ($1), Tourism and Promotion ($.5) and Vehicle Rental Tax ($1); and transfer from Environmental Remediation to capital projects ($2). The capital projects fund balances increased $123 million due to the issuance of tax supported debt, with the most significant increases in fund balances inthe following funds (in millions): Cultural arts and land ($21), Traffic signals ($47), CMTA Mobility ($19) and City hall, plaza, parking garage ($25). b - Proprietary funds The City s proprietary funds provide the same type of information found in the government-wide financial statements, but in more detail.
- Total Electric Fund net assets increased $105 million. Operating revenue for 2002 was $745 million, a decrease of approximately 8% from the prior year. This decrease was primarily due to reduced fuel costs, which are recovered as a component of the electric rate, and reduced demand due to moderate weather conditions. Operating expense before depreciation for 2002 was $401 million, a decrease of approximately 12% from the prior year. This decrease was primarily due to reduced fuel costs.
- Total Water and Wastewater Fund net assets decreased approximately $8 million. Operating revenue for 2002 was
$230 million, an increase of approximately 4% from the prior year. Sales were less than projected due to economic conditions and wetter than normal weather conditions throughout the year. City Council approved a 7% and 4.5%
rate increase for water and wastewater services, respectively, effective in November 2001 to meet increased annual revenue requirements for operations and maintenance and the Utility's capital improvements program. Operating expense before depreciation for 2002 was $112 million, an increase of approximately 10% over the prior year. The increase in expenses was due in part from unplanned security costs, a flood, and water transmission breaks and the related operating expenses. The utility implemented cost containment strategies to reduce other operating costs during 2002. Interest revenues were $9.6 million, a decrease of approximately 29% from prior year due to lower interest rates. The City issues revenue bonds for the construction of certain additions, improvements, and extensions of the City s water and wastewater delivery systems. The debt service requirements were reduced through a bond refunding and lower commercial paper interest costs due to reduced commercial paper issuances resulting from lower than planned spending for capital projects. 11
i ' Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) FINANCIAL ANALYSIS OF THE GOVERNMENT S FUND LEVEL STATEMENTS, continued The Airport Fund net assets increased over $8 million in 2002. Operating revenues were $64 million, a decrease from the prior year, as airline traffic across the nation declined in the aftermath of September 11. Airport management took action to reduce operating expenses immediately, resulting in a decrease in expenses of approximately $2 million. The fund also incurred costs for new airport security requirements and the Airport management met the Federal mandate to staff security checkpoints with Federal employees. Nonoperating revenues and expenses and capital contributions resulted in the remaining increase in net assets. OTHER INFORMATION a - General Fund budgetary highlights The final amended budget for General Fund was $283 thousand more than the original budget. Changes in the budget include the following:
* $3 million net increase in revenues, with a $3 million decrease in sales tax budget and a $6 million increase in other revenues.
* $2 million increase in transfers in, primarily for homeland security for utility funds.
* $4 million increase in public safety expenses, funded by General Fund and by Electric and Water and Wastewater utility funds
* $1 million increase in transfers out During the year, revenues were $8 million less than budgeted. Cost containment steps were put into place to reduce expenditures, thus setting aside resources for 2003. The expenditure budget was not formally amended to reflect the cost containment actions.
Costs on the City s basis of budgeting resulted in $380 million in charges to appropriations, as follows:
- Public safety costs of S239 million
- Public health costs of $54 million
- Public recreation and culture costs of $47 million
- Costs of general government; transportation, planning and sustainability; urban growth management and general city responsibilities of $40 million Programs with significant savings included public safety; transportation, planning and sustainability; public health; and public recreation and culture.
b - Capital Assets The City s capital assets for governmental and business-type activities as of September 30, 2002, amount to $6.5 billion (net of accumulated depreciation). Capital assets include land, buildings and improvements, equipment, vehicles, infrastructure, assets not classified, construction work in progress, nuclear fuel and plant held for future use. The total increase in the City s capital assets for the current fiscal year was $319 million (5 percent), with an increase of almost 6 percent for governmental activities and an increase of almost 5 percent for business-type activities. Capital asset balances are, as follows: Capital Assets, Net of Accum ulated Depreciation September 30, 2002 (in millions) Governmental Business-Type Activities Activities Total Land and improvements $ 151 267 418 Other assets not depreciated 17 1 18 Building and improvements 189 1,984 2,173 Equipment 17 1,571 1,588 Vehicles 34 36 70 hifrastructure 867 - 867 Cornpleted assets not classified 190 555 745 Construction workin progress 223 311 534 Nuclear fuel, net of amortization - 18 18 Rant held for future use 31 31 31 Total net assets $ 1,688 4,774 6,462 6,462 12
Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued) OTHER INFORMATION, continued Major capital asset events during the current fiscal year included the following:
- Governmental capital assets increased $95 million, with construction continuing on public safety facilities, a new City Hall and cultural and recreational facilities; included were increases in infrastructure assets of $32 million for annexations and developer dedications at estimated fair market value.
- Business-type activities purchased or completed construction on capital assets of $224 million, with Electric and Water and Wastewater funds continuing expansion or improvements to existing facilities. The Convention Center, a nonmajor fund, opened facilities during the year ($101 million).
Additional information on capital assets can be found in Note 7. c - Debt Administration At the end of the current fiscal year, the City reported $4.5 billion in outstanding debt. Of this amount, $795 million is general obligation debt backed by the full faith and credit of the City; $3.7 billion is revenue bonds, commercial paper, and other bonded debt. In addition, the City reported other long-term obligations of $0.8 billion. Additional information can be found in Note 10. Outstanding Debt General Obligation and Revenue Debt (in millions) Governmental Business-Activities Type Activities Total General obligation bonds and other tax supported debt, net $ 795 85 880 Revenue bonds, net - 3,196 3,196 Commercial paper notes, net - 358 358 Revenue notes - 28 28 Capital lease obligations - 17 17 Total $ 795 3,684 4,479 During fiscal year 2002, the City s total long-term obligations increased by $305 million. The City issued new debt and refinanced some existing debt to take advantage of lower interest rates or changes in bond covenants. Issues include the following:
- Bonded debt for governmental functions increased $221 million, and will be used primarily for the following: public safety equipment and facilities; parks and library facilities; a new City Hall; street improvements, right of way acquisition and utility relocation; communication equipment; asbestos abatement; and refunding bonds of $14.7 million. Other obligations increased $10 million.
- Bonded debt for business-type functions increased $31 million, and will be used primarily for refunding utility bonds, utility relocation, convention center improvements, solid waste equipment and facilities improvements. During the year, the City continued efforts to separate debt for Electric and Water and Wastewater activities. In 2002, the City issued Electric refunding and Water and Wastewater refunding bonds to refund outstanding combined utility bonds.
Other business-type obligations increased $43 million. 13
- i Management Discussion and Analysis City of Austin, Texas September 30, 2002 (Continued)
OTHER INFORMATION, continued The City continues to maintain excellent credit ratings on debt issues, with ratings remaining unchanged during the year. The following are ratings at September 20, 2002 of the City s obligations for various debt instruments, as follows: Moodys Investors Standard and Debt Service, Inc Poors Fitch, Inc. General obligation bonds and other tax supported debt Aa2 AA+ AA+ Revenue bonds - prior lien A2 A A+ Revenue bonds - subordinate lien A2 A- A+ Commercial paper notes P-1 Ai F1+ Commercial paper notes-taxable P-1 A-1+ F1+ d - Economic Factors and Next Year s Budget and Rates The Citys elected officials and management considered many factors when setting the fiscal year 2003 budget. With the events of September 11, the City s public safety costs increased and tourism-related revenues declined, and generally mild weather conditions reduced utility revenues. In addition, the technology slump has hit the City especially hard. The City is experiencing higher unemployment rates than in recent years. In mid-2002, the City began a savings plan to build reserves for 2003. The City implemented aggressive cost containment saving measures, with City departments identifying one-time or on-going cost savings. City management reduced costs through implementation of process improvements for greater efficiencies. Examples of cost containment actions included restricting travel, reducing consultant costs, reducing costs of temporary personnel and overtime, and holding vacant positions open. As part of the 2003 budget, the City maintained basic City services, retained the same tax rate, held utility rates unchanged and reduced the number of employee positions by cutting more than 300 vacant positions. In early 2003, City management provided information to the City Council to begin planning for the 2004 budget, which must address lower sales and property tax revenues. a - Requests for Information This financial report is designed to provide our citizens, taxpayers, customers, and investors and creditors with a general overview of the City s finances and to demonstrate the City s accountability for the money it receives. If you have questions about this report or need additional financial information, contact the Financial Services Department of the City of Austin, P.O. Box 1088, Austin, Texas 78767, or 512-974-3344 or on the web at htto://www.ci.austin.tx.us/finance/. 14
BASIC FINANCIAL STATEMENTS
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Statement of Net Assets City of Austin, Texas September 30, 2002 Exhibit A-1 (In thousands) Governmental Business-type 2002 Activities Activities Total ASSETS Current assets: Cash $ 112 51 163 Pooled investments and cash 463,777 143,156 606,933 Pooled investments and cash - designated - 96,481 96,481 Total pooled investments and cash 463,777 239,637 703,414 Investments, at fair value - designated 16,794 169,068 185,862 Cash held by trustee 402 - 402 Working capital advances - 3,833 3,833 Property taxes receivable 10,075 - 10,075 Less allowance for uncollectible taxes (1,716) - (1,716) Net property taxes receivable 8,359 - 8,359 Accounts and other taxes receivable 143,400 128,348 271,748 Less allowance for doubtful accounts (79,876) (8,108) (87,984) Net accounts receivable 63,524 120,240 183,764 Receivables from other governments 11,343 743 12,086 Notes receivable, net of allowance 7,225 - 7,225 Internal balances (6,579) 2,584 - Inventories, at cost 2,982 50,190 53,172 Real property held for resale 5,717 - 5,717 Prepaid expenses and other expenses 2,095 6,889 8,984 Total current assets 575,751 593,235 1,172,981 Restricted assets Pooled investments and cash - 266,268 266,268 Investments, at fair value - 248,840 248,840 Cash held by trustee _ 13,338 13,338 Investments held by trustee _ 77,539 77,539 Interest receivable _ 3,729 3,729 Receivable from other governments - 1,684 1,684 Internal balances _ 3,995 Other receivables -____________ 800 800 Total restricted assets - 616,193 612,198 Noncurrent assets: Noncurrent investments 65,000 65,000 Capital assets Land and other nondepreciable assets 168,470 267,836 436,306 Property, plant and equipment in service 1,802,722 6,143,458 7,946,180 Less accumulated depreciation (506,583) (1,997,224) (2,503,807) Net property, plant and equipment in service 1,296,139 4,146,234 5,442,373 Construction in progress 223,455 310,876 534,331 Nuclear fuel (net of amortization) - 18,102 18,102 Plant held for future use - 31,379 31,379 Total capital assets 1,688,064 4,774,427 6,462,491 Intangible assets, net of amortization - 92,602 92,602 Other long-term assets - 5,350 5,350 Deferred costs and expenses, net of amortization 877 634,260 635,137 Total noncurrent assets 1,688,941 5,571,639 7,260,580 Total assets $ 2,264,692 6,781,067 9,045,759 (Continued) ( ) After internal receivables and payables have been eliminated. The accompanying notes are an integral part of the financial statements. 16
Statement of Net Assets City of Austin, Texas September 30, 2002 Exhibit A-I (In thousands) (Continued) Governmental Business-type 2002 Activities Activities Total( ) LIABILITIES Current liabilities: Accounts payable $ 36,366 52,415 88,781 Accrued payroll 8,689 5,320 14,009 Accrued compensated absences 4,762 12,416 17,178 Claims payable 23,529 23,529 Interest payable on other debt 4,244 2,166 6,410 General obligation bonds payable and other tax supported debt, net of discount and inclusive of premium 45,467 3,142 48,609 Revenue bonds payable - 2,355 2,355 Capital lease obligations payable - 2,433 2,433 Tax anticipation notes payable 4,800 - 4,800 Deferred credits and other liabilities 57,261 25,292 82,553 Total current liabilities 185,118 105,539 290,657 Liabilities payable from restricted assets: Accounts and retainage payable - 43,098 43,098 Accrued interest payable - 63,834 63,834 Current portion of general obligation bonds payable - 5,348 5,348 Current portion of revenue bonds payable - 95,711 95,711 Customer and escrow deposits - 7,076 7,076 Decommissioning expense payable - 81,727 81,727 Nuclear fuel expense payable - 33,234 33,234 Other liabilities - 2,635 2,635 Total liabilities payable from restricted assets - 332,663 332,663 Noncurrent liabilities, net of current portion: Accrued compensated absences 59,438 8,7E33 68,201 Claims payable 9,852 - 9,852 Capital appreciation bond interest payable -141,3W 90 141,390 Commercial paper notes payable, net of discount -358,3! 51 358,351 Revenue notes payable -28,0( 00 28,000 General obligation bonds payable and other tax supported debt, net of discount and Inclusive of premium 749,560 76,507 826,067 Revenue bonds payable, net of discount and inclusive of premium - 3,098,022 3,098,022 Capital lease obligations payable - 14,204 - 14,204 Accrued landfill closure and postclosure costs 7,188 7,188 Deferred credits and other liabilities 13,287 453,736 467,023 Total noncurrent liabilities 832,137 4,186,161 5,018,298 Total liabilities 1,017,255 4,624,363 5641T61 NET ASSETS Invested in capital assets, net of related debt 1,111,491 1,196,098 2,307,589 Restricted for: Debt service 12,302 75,314 87,616 Bond reserve 18,687 18,687 Capital projects 14,678 88,508 103,186 Renewal and replacement 10,978 10,978 Passenger facility charges 9,164 9,164 Perpetual Care: Expendable 284 - 284 Nonexpendable 1,040 - 1,040 Other purposes 188 - 188 Unrestricted 107,454 757,955 865,409 Total net assets $ 1,247,437 2,156,704 3,404,141 ( ) After internal receivables and payables have been eliminated. The accompanying notes are an integral part of the financial statements. 17
Statement of Activities City of Austin, Texas For the year ended September 30, 2002 Exhibit A-2 (In thousands) Net (EExpense) Revenue and Program Revenues Ch; anges in Net Assets Operating Capital Charges for Grants and Grants and Governmental Business-type 2002 Functions/Programs Expenses Services Contributions Contributions Activities Activities Total Governmental activities General government $ 75,941 12,964 322 - (62,655) - (62,655) Public safety 279,533 36,226 5,001 - (238,306) - (238,306) Transportation, planning and sustainability 15,694 4,948 82 619 (10,045) - (10,045) Public health 75,033 6,969 15,691 202 (52,171) - (52,171) Public recreation and culture 71,863 2,499 5,439 345 (63,580) - (63,580) Urban growth management 54,287 20,743 26,839 37 (6,668) - (6,668) Unallocated depreciation expense 34,074 - - - (34,074) - (34,074) Interest on debt 35,771 - - - (35,771) - (35,771) Total governmental activities 642,196 84,349 53,374 1,203 (503,270) - (503,270) Business-type activities Electric 610,374 745,095 - 3,736 133,457 138,457 Water and Wastewater 251,171 229,534 - 27,413 5,776 5,776 Airport 76,546 72,777 - 8,905 5,136 5,136 Convention 36,344 10,376 - - (25,968) (25,968) Other 115,518 116,973 - 3,483 - 4,938 4,938 Total business-type activities 1,089,953 1,174,755 - 43,537 - 128,339 128,339 Total $ 1,732,149 1,259,104 53,374 44,740 (503,270) 128,339 (374,931) General revenues: Property tax 224,396 - 224,396 Sales tax 115,441 _ 115,441 Franchise fees and gross receipts tax 62,576 - 62,576 Grants and contributions not restricted to specific programs 19,137 _ 19,137 Interest and other 23,746 58,1 80 81,926 {Auuj - Special Items - purchased land lease rights (4,000) _ _ t4,'UUUJ Transfers 104,519 (104,519) _ Total general revenues and transfers 545,815 (46,339) 499,476 Change In net assets 42,545 82,000 124,545 Beginning net assets 1,204,892 2,074,704 3,279,596 Ending net assets $ 1,247,437 2,156,704 3,404,141 The accompanying notes are an Integral part of the financial statements.
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Governmental Funds City of Austin, Texas Balance Sheet Exhibit B-1 September 30, 2002 (In thousands) 2002 Nonmajor Total General Governmental Governmental Fund Funds Funds ASSETS Cash $ 89 5 94 Pooled investments and cash 88,956 302,240 391,196 Investments, at fair value - 16,794 16,794 Property taxes receivable 6,107 3,968 10,075 Less allowance for uncollectible taxes (1,038) (678) (1,716) Net property taxes receivable 5,069 3,290 8,359 Accounts and other taxes receivable 72,323 16,261 88,584 Less allowance for doubtful accounts (43,477) (388) (43,865) Net accounts receivable 28,846 15,873 44,719 Receivables from other governments - 11,343 11,343 Notes receivable, net of allowance - 7,225 7,225 Due from other funds - 12,944 12,944 Advances to other funds - 2,479 2,479 Inventories, at cost 881 - 881 Real property held for resale _ 5,717 5,717 Prepaid expenses and other assets 220 1,637 1,857 Total assets 124,061 379,547 503,608 LIABILITIES AND FUND BALANCES Accounts payable 4,721 26,492 31,213 Accrued payroll 6,771 41 6,812 Accrued compensated absences 605 6 611 Due to other funds 724 13,366 14,090 Deferred revenue 4,988 6,685 11,673 Advances from other funds 2,918 135 3,053 Tax anticipation notes payable 4,800 - 4,800 Deposits and other liabilities 4,916 43,035 47,951 Total liabilities 30,443 89,760 120,203 Fund balances Reserved: Encumbrances 4,951 87,508 92,459 Inventories and prepaid items 1,101 1,101 Notes receivable 7,225 7,225 Real property held for resale 5,717 5,717 Debt service 16,451 16,451 Permanent funds 1,040 1,040 Unreserved, designated: Emergencies 15,000 15,000 Contingencies 2,948 2,948 Future use 540 23,686 24,226 Public Health 33,000 33,000 Unreserved, undesignated: General Fund 36,078 - 36,078 Capital projects - 147,876 147,876 Permanent funds - 284 284 Total fund balances 93,618 289,787 383,405 Total liabilities and fund balances $ 124,061 379,547 503,608 The accompanying notes are an integral part of the financial statements. 20
Governmental Funds City of Austin, Texas Reconciliation of the Governmental Funds Balance Sheet Exhibit B-1.1 to the Statement of Net Assets September 30, 2002 (In thousands) Total fund balances - Governmental funds $ 383,405 Amounts reported for governmental activities in the statement of net assets are different because: Capital assets used in governmental activities are not financial resources and, therefore, are not reported in the funds. 1,656,236 Other long-term assets are not available as current-period resources and are not reported in the funds. 27,923 Internal service funds are used by management to charge the costs of fleet maintenance, support services, Information systems, employee benefits, liability reserve, workers compensation. radio communication, infrastructure support services and capital project management to individual funds. The assets and liabilities of the internal service funds are included in governmental activities in the statement of net assets. 37,848 Long-term liabilities are not payable in the current period and are not reported In the funds. (857,975) Total net assets - Governmental activities -V-T77.Mr 21
Governmental Funds City of Austin, Texas Statement of Revenues, Expenditures and Changes in Fund Balances Exhibit B-2 For the year ended September 30, 2002 (In thousands) 2002 Nonmajor Total General Governmental Governmental Fund Funds Funds REVENUES Property taxes $ 143,056 72,782 215,838 Sales taxes 115,441 - 115,441 Franchise fees and other taxes 33,282 29,153 62,435 Fines, forfeitures and penalties 17,704 3,986 21,690 Licenses, permits and inspections 14,670 - 14,670 Charges for services/goods 15,579 25,220 40,799 Intergovernmental - 62,141 62,141 Property owners' participation and contributions - 13,214 13,214 Interest and other 6,028 19,373 25,401 Total revenues 345,760 225,869 571,629 EXPENDITURES Current: General government 54,397 1,044 55,441 Public safety 250,081 13,177 263,258 Transportation, planning and sustainability 10,342 3,476 13,818 Public health 54,525 20,528 75,053 Public recreation and culture 49,216 10,439 59,655 Urban growth management 11,676 45,844 57,520 Debt service: Principal - 44,382 44,382 Interest - 36,566 36,566 Fees and commissions 7 7 Capital outlay - 174,239 174,239 Total expenditures 430,237 349,702 779,939 Excess (deficiency) of revenues over expenditures (84,477) (123,833) (208,310) OTHER FINANCING SOURCES (USES) Issuance of tax supported debt - 254,505 254,505 Issuance of refunding bonds - 14,685 14,685 Payment to escrow agent - (14,685) (14,685) Transfers in 137,084 39,794 176,878 Transfers out (9,424) (58,040) (67,464) Total other financing sources (uses) 127,660 236,259 363,919 Excess (deficiency) of revenues and other sources over expenditures and other uses 43,183 112,426 155,609 Special items - purchased land lease rights - (4,000) (4,000) Net change in fund balances 43,183 108,426 151,609 Fund balances at beginning of year 50,435 181,361 231,796 Fund balances at end of year $ 93,618 289,787 383,405 The accompanying notes are an integral part of the financial statements. 22
Governmental Funds City of Austin, Texas Reconciliation of the Governmental Funds Statement of Revenues, Expenditures and Exhibit B-2.1 Changes In Fund Balances to the Statement of Activities For the Year Ended September 30, 2002 (In thousands) Net change in fund balances - Governmental funds $ 151,609 Governmental funds report capital outlays as expenditures. However, in the statement of activities the cost of those assets is allocated over their estimated useful lives and reported as depreciation expense. This is the amount by which capital outlays exceeded depreciation in the current period. 98,531 Revenues in the statement of activities that do not provide current available financial resources are not reported as revenues in the funds. 28,160 Revenues in the governmental funds are recognized when measurable and available, but are deferred in the statement of activities until earned, regardless of when collected. (14,011) The issuance of long-term debt (e.g., bonds, leases) provides current financial resources to governmental funds, while the repayment of the principal of long-term debt consumes the current financial resources of governmental funds. Neither transaction, however, has any effect on net assets. Also, governmental funds report the effect of issuance costs, premiums, discounts, and similar items when debt is first issued, whereas these amounts are deferred and amortized in the statement of activities. This amount is the net effect of these differences in the treatment of long-term debt and related items. (216,864) Some expenses reported in the statement of activities do not require the use of current financial resources and therefore are not reported as expenditures in the funds. 2,623 The net revenue of certain activities of internal service funds is reported with governmental activities. (7,503) Change in net assets - Governmental activities $ 42,545 23
Proprietary Funds Statement of Net Assets September 30, 2002 (In thousands) Water and Electric Wastewater Airport ASSETS Current assets: Cash $ 18 12 6 Pooled investments and cash 96,041 16,154 6,605 Pooled investments and cash - designated 38,546 37,856 Total pooled investments and cash 134,587 54,010 6,605 Investments, at fair value - designated 158,660 10,408 Cash held by trustee Working capital advances 3,709 Accounts receivable 88,648 23,052 1,459 Less allowance for doubtful accounts (3,217) (995) (150) Net accounts receivable 85,431 22,057 1,309 Receivables from other governments Due from other funds Inventories, at cost 48,812 833 I-Prepaid expenses and other assets 6,621 115 1 Total current assets 437,838 87,435 7,921 Restricted assets Pooled investments and cash 59,147 55,735 83,135 Investments, at fair value 130,668 79,563 25,709 Cash held by trustee 7,722 5,616 Investments held by trustee 77,539 Interest receivable 2,767 695 Receivable from other governments 210 1,474 Due from other funds 27 700 Advances to other funds 215 3,029 Other receivables 273 527 Total restricted assets 278,326 142,378 114,047 Noncurrent assets: Noncurrent investments 65,000 Capital assets Land and other nondepreciable assets 32,877 135,325 59,095 Property, plant and equipment in service 2,988,488 2,104,864 615,577 Less accumulated depreciation (1,203,986) (616,552) (72,379) Net property, plant and equipment in service 1,784,502 1,488,312 543,198 Construction in progress 160,485 104,100 7,802 Nuclear fuel (net of amortization) 18,102 Plant held for future use 31,379 Total capital assets 2,027,345 1,727,737 610,095 Intangible assets, net of amortization 92,602 Other long-term assets 3,961 1,389 Deferred costs and expenses, net of amortization 361,735 251,776 2,191 Total noncurrent assets 2,458,041 2,073,504 612,286 Total assets $ 3,174,205 2,303,317 734,254 The accompanying notes are an integral part of the financial statements. 24
City of Austin, Texas Exhibit C-1 Governmental Nonmajor Activities-Enterprise 2002 Internal Service Funds Total Funds ASSETS Current assets: Cash 15 51 18 Pooled investments and cash 24,356 143,156 72,581 Pooled investments and cash - designated 20,079 96,481 Total pooled investments and cash 44,435 239,637 72,581 Investments, at fair value - designated 169,068 Cash held by trustee 402 Working capital advances 124 3,833 Accounts receivable 15,189 128,348 742 Less allowance for doubtful accounts (3,746) (8,108) (222) Net accounts receivable 11.443 120,240 520 Receivables from other governments 743 743 Due from other funds 1,689 1,689 Inventories, at cost 545 50,190 2,101 Prepaid expenses and other assets 152 6,889 238 Total current assets 59,146 592,340 75,860 Restricted assets Pooled investments and cash 68,251 266,268 Investments, at fair value 12,900 248,840 Cash held by trustee 13,338 Investments held by trustee 77,539 Interest receivable 267 3,729 Receivable from other governments 1,684 Due from other funds 727 Advances to other funds 24 3,268 Other receivables 800 Total restricted assets 81,442 616,193 Noncurrent assets: Noncurrent investments 65,000 Capital assets Land and other nondepreciable assets 40,539 267,836 486 Property, plant and equipment in service 434,529 6,143,458 54,807 Less accumulated depreciation (104,307) (1,997,224) (23,465) Net property, plant and equipment in service 330,222 4,146,234 31,342 Construction in progress 38,489 310,876 Nuclear fuel (net of amortization) - 18,102 Plant held for future use - 31,379 Total capital assets 409,250 4,774,427 31,828 Intangible assets, net of amortization - 92,602 Other long-term assets - 5,350 Deferred costs and expenses, net of amortization 18,558 634,260 7 Total noncurrent assets 427,808 5,571,639 31,835 Total assets 568,396 6,780,172 107,695 The accompanying notes are an integral part of the financial statements. (Continued) 25
. Proprietary Funds Statement of Net Assets September 30, 2002 (In thousands) Water and Electric Wastewater Airport LIABILITIES Current liabilities: Accounts payable $ 40,056 2,251 4,995 Accrued payroll 2,209 1,221 392 Accrued compensated absences 5,447 2,983 794 Claims payable Due to other funds Interest payable on other debt 641 1,308 7 General obligation bonds payable and other tax supported debt, net of discount and inclusive of premium 135 Revenue bonds payable 2,355 Capital lease obligations payable 1,533 900 Deferred credits and other liabilities 22,534 1,906 288 Total current liabilities 72,420 12,924 6,611 Uabilities payable from restricted assets: Accounts and retainage payable 19,671 16,199 1,697 Accrued interest payable 29,315 20,880 8,514 Current portion of general obligation bonds payable 363 4,615 Current portion of revenue bonds payable 67,081 19,745 5,630 Customer and escrow deposits 3,892 1,313 420 Decommissioning expense payable 81,727 Nuclear fuel expense payable 33,234 Other liabilities 1,616 246 773 Total liabilities payable from restricted assets 236,899 62,998 17,034 Noncurrent liabilities, net of current portion: Accrued compensated absences 4,489 1,982 452 Claims payable Advances from other funds 1,733 Capital appreciation bond interest payable 80,583 60,807 Commercial paper notes payable, net of discount 200,509 157,842 Revenue notes payable 28,000 General obligation bonds payable and other tax supported debt, net of discount and inclusive of premium 2,367 27,055 725 Revenue bonds payable, net of discount and inclusive of premium 1,345,895 1,161,974 356,710 Capital lease obligations payable 8,504 5,700 Accrued landfill closure and postclosure costs Deferred credits and other liabilities 62,477 387,637 3,618 Total noncurrent liabilities 1,704,824 1,804,730 389,505 Total liabilities 2,014,143 1,880,652 413,150 NET ASSETS Invested in capital assets, net of related debt 612,186 203,249 221,482 Restricted for Debt service 40,862 14,979 19,435 Bond reserve 5,632 13,055 Capital projects 53,116 Renewal and replacement 10,000 Passenger facility charges 9,164 Unrestricted 501,382 191,382 7,907 Total net assets $ 1,160,062 422,665 321,104 Reconciliation to govemment-wide Statement of Net Assets Adjustment to consolidate internal service activities 1,597 1,461 454 Total net assets - Business-type activities $ 1,161,659 424,126 321,558 The accompanying notes are an integral part of the financial statements. 26
City of Austin, Texas Exhibit C-1 (Continued) Governmental Nonmajor Activities-Enterprise 2002 Internal Service Funds Total Funds LIABILITIES Current liabilities: Accounts payable 5,113 52,415 5,153 Accrued payroll 1,498 5,320 1,877 Accrued compensated absences 3,192 12,416 4,151 Claims payable 23,529 Due to other funds 1,243 1,243 27 Interest payable on other debt 210 2,166 95 General obligation bonds payable and other tax supported debt, net of discount and inclusive of premium 3,007 3,142 1,482 Revenue bonds payable 2,355 Capital lease obligations payable 2,433 Deferred credits and other liabilities 564 25,292 1,057 Total current liabilities 14,827 106,782 37,371 Uabilities payable from restricted assets: Accounts and retainage payable 5,531 43,098 Accrued interest payable 5,125 63,834 Current portion of general obligation bonds payable 370 5,348 Current portion of revenue bonds payable 3,255 95,711 Customer and escrow deposits 1,451 7,076 Decommissioning expense payable 81,727 Nuclear fuel expense payable 33,234 Other liabilities 2,635 Total liabilities payable from restricted assets 15,732 332,663 Noncurrent liabilities, net of current portion: Accrued compensated absences 1,840 8,763 2,727 Claims payable 9,852 Advances from other funds 639 2,372 322 Capital appreciation bond interest payable 141,390 Commercial paper notes payable, net of discount 358,351 Revenue notes payable 28,000 General obligation bonds payable and other tax supported debt, net of discount and inclusive of premium 46,360 76,507 15,065 Revenue bonds payable, net of discount and inclusive of premium 233,443 3,098,022 Capital lease obligations payable 14,204 Accrued landfill closure and postclosure costs 7,188 7,188 Deferred credits and other liabilities 4 453,736 Total noncurrent liabilities 289,474 4,188,533 27,966 Total liabilities 320,033 4,627,978 65,337 NET ASSETS Invested in capital assets, net of related debt 159,181 1,196,098 15,288 Restricted For Debt service 38 75,314 Bond reserve 18,687 Capital projects 35,392 88,508 12,388 Renewal and replacement 978 10,978 Passenger facility charges 9,164 Unrestricted 52,774 753,445 14,682 Total net assets 248,363 2,152,194 42,358 Reconciliation to govemment-wide Statement of Net Assets Adjustment to consolidate internal service activities 998 4,510 Total net assets - Business-type activities 249,361 2,156,704 The accompanying notes are an integral part of the financial statements. 27
Proprietary Funds Statement of Revenues, Expenses and Changes in Fund Net Assets For the year ended September 30, 2002 (In thousands) Water and Electric Wastewater Airport OPERATING REVENUES Utility services $ 745,095 229,534 User fees and rentals ~
- 64,418 Billings to departments Employee contributions Operating revenues from other governments Other operating revenues Total operating revenues 745,095 229,534 64,418 OPERATING EXPENSES Operating expenses before depreciation 401,439 112,340 37,265 Depreciation and amortization 90,253 54,240 16,210 Total operating expenses 491,692 166,580 53,475 Operating income (loss) 253,403 62,954 10,943 NONOPERATING REVENUES (EXPENSES)
Interest and other revenues 38,716 9,643 4,039 Interest on revenue bonds and other debt (97,149) (74,962) (23,648) Interest capitalized during construction 435 Passenger facility charges 8,359 Amortization of bond issue cost (652) (456) (105) Deferred costs recovered (16,557) (10,670) Other nonoperating revenue (expense) (5,921) 36 (207) Total nonoperating revenues (expenses) (81,563) (76,409) (11,127) Income (loss) before contributions and transfers 171,840 (13,455) (184) Capital contributions 3,736 27,413 8,905 Transfers in Transfers out (70,123) (22,044) (50) Change in net assets 105,453 (8,086) 8,671 Total net assets - beginning 1,054,609 430,751 312,433 Total net assets - ending $ 1,160,062 422,665 321,104 Reconciliation to government-wide Statement of Activities Change in net assets 105,453 (8,086) 8,671 Adjustment to consolidate internal service activities 1,597 1,461 454 Change in net assets - Business-type activities $ 107,050 (6,625) 9,125 The accompanying notes are an integral part of the financial statements. 28
City of Austin, Texas Exhibit C-2 Governmental Nonmajor Activities-Enterprise 2002 Internal Service Funds Total Funds OPERATING REVENUES Utility services 974,629 User fees and rentals 124,189 188,607 Billings to departments 185,447 Employee contributions 20,804 Operating revenues from other governments 3,116 3,116 - Other operating revenues 44 44 3,868 Total operating revenues 127,349 1,166,396 210,119 OPERATING EXPENSES Operating expenses before depreciation 124,649 675,693 205,781 Depreciation and amortization 14,860 175,563 2,949 Total operating expenses 139,509 851,256 208,730 Operating income (loss) (12,160) 315,140 1,389 NONOPERATING REVENUES (EXPENSES) Interest and other revenues 5,782 58,180 983 Interest on revenue bonds and other debt (16,332) (212,091) (477) Interest capitalized during construction 3,523 3,958 Passenger facility charges 8,359 Amortization of bond issue cost (173) (1,386) (4) Deferred costs recovered (27,227) Other nonoperating revenue (expense) (369) (6,461) (129) Total nonoperating revenues (expenses) (7,569) (176,668) 373 Income (loss) before contributions and transfers (19,729) 138,472 1,762 Capital contributions 3,483 43,537 140 Transfers in 37,319 37,319 393 Transfers out (49,621) (141,838) (5,288) Change In net assets (28,548) 77,490 (2,993) Total net assets - beginning 276,911 2,074,704 45,351 Total net assets - ending 248,363 2,152,194 42,358 Reconciliation to govemment-wide Statement of Activities Change in net assets (28,548) 77,490 Adjustment to consolidate internal service activities 998 4,510 Change in net assets - Business-type activities (27,550) 82,000 The accompanying notes are an integral part of the financial statements. 29
Proprietary Funds Statement of Cash Flows For the year ended September 30, 2002 (In thousands) Water and Electric Wastewater Airport CASH FLOWS FROM OPERATING ACTIVITIES: Cash received from customers $ 826,463 228,862 67,857 Cash payments to suppliers for goods and services (310,629) (57,079) (24,865) Cash payments to employees for services (92,651) (53,780) (17,098) Cash payments to claimants/beneficaries Cash received from other governments Taxes collected and remitted to other governments (22,282) - - Net cash provided (used) by operating activities 400,901 118,003 25,894 CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES: Transfers in Transfers out (70,123) (22,044) (50) Interest paid on revenue notes and other debt (418) (11) Increase in deferred assets (780) Contributions from municipality Loans to other funds Loans from other funds -___________ 1,733 589 Net cash provided (used) by noncapital financing activities (71,321) (20,322) 539 CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES: Proceeds from the sale of commercial paper notes 50,171 79,616 Proceeds from the sale of general obligation bonds and other tax supported debt 1,765 Principal paid on long-term debt (82,223) (30,540) (3,387) Proceeds from the sale of fixed assets 2,401 Purchased interest received 1,329 1,121 Interest paid on revenue bonds and other debt (98,652) (69,670) (23,178) Passenger facility charges 8,359 Acquisition and construction of capital assets (187,370) (101,594) (16,970) Contributions from municipality Contributions from State and Federal governments 8,015 Contributions in aid of construction 3,269 7,731 83 Bond discounts and issuance costs (2,951) (2,832) Bond premiums 22,132 17,125 Bonds issued for advanced refundings of debt 247,630 235,075 Cash paid for bond refunding escrow (293,080) (249,368) Cash paid for nuclear fuel inventory (7,818) Net cash provided (used) by capital and related financing activities $ (347,563) (109,170) (27,078) The accompanying notes are an integral part of the financial statements. 30
City of Austin, Texas Exhibit C-3 Governmental Nonmajor Activities-Enterprise 2002 Internal Service Funds Total Funds CASH FLOWS FROM OPERATING ACTIVITIES: Cash received from customers 121,406 1,244,588 209,916 Cash payments to suppliers for goods and services (55.001) (447,574) (65,682) Cash payments to employees for services (65,504) (229,033) (85,935) Cash payments to claimants/beneficaries (44,103) Cash received from other governments 4,314 4,314 Taxes collected and remitted to other governments (22,282) Net cash provided (used) by operating activities 5,215 550,013 14,196 CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES: Transfers in 35,210 35,210 393 Transfers out (49,621) (141,838) (5,288) Interest paid on revenue notes and other debt (14) (443) Increase in deferred assets (780) Contributions from municipality 20 Loans to other funds (1,713) (1,713) Loans from other funds 669 2,991 Net cash provided (used) by noncapital financing activities (15,469) (106,573) (4,875) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTMTIES: Proceeds from the sale of commercial paper notes - 129,787 Proceeds from the sale-of general obligation bonds and other tax supported debt 21,865 23,630 11,725 Principal paid on long-term debt (6,271) (122,421) (1,152) Proceeds from the sale of fixed assets 2,401 Purchased interest received 23 2,473 Interest paid on revenue bonds and other debt (15,946) (207,446) (451) Passenger facility charges 8,359 Acquisition and construction of capital assets (80,884) (386,818) (9,386) Contributions from municipality 6,452 Contributions from State and Federal governments 8,015 Contributions in aid of construction 2,110 13,193 Bond discounts and issuance costs (5,783) Bond premiums 81 39,338 Bonds issued for advanced refundings of debt 482,705 Cash paid for bond refunding escrow (542,448) Cash paid for nuciear fuel inventory (7,818) Net cash provided (used) by capital and related financing activities (79,022) (562,833) 7,188 The accompanying notes are an Integral part of the financial statements. (Continued) 31
Proprietary Funds Statement of Cash Flows For the year ended September 30, 2002 (In thousands) Water and Water and Electric Wastewater Airport CASH FLOWS FROM INVESTING ACTIVITIES: Purchase of investment securities $ (313,658) (136,800) (39,361) Proceeds from sale and maturities of investment securities 340,678 136,733 37,223 Interest on investments 27,536 9,104 3,121 Net cash provided by investing activities 54,556 9,037 983 Net increase (decrease) in cash and cash equivalents 36,573 (2,452) 338 Cash and cash equivalents, October 1 164,901 117,825 89,408 Cash and cash equivalents, September 30 201,474 115,373 89,746 RECONCILIATION OF OPERATING INCOME TO NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES: Operating income (loss) 253,403 62,954 10,943 Adjustments to reconcile operating income to net cash provided by operating activities: Depreciation 90,253 51,740 16,210 Amortization 2,500 Change in assets and liabilities: (Increase) in working capital advances (818) (Increase) decrease in accounts receivable 15,311 (139) 3,325 (Decrease) in allowance for doubtful accounts (1,093) Decrease in receivable from other governments (Increase) decrease in inventory (1,163) 246 (Increase) decrease in prepaid expenses and other assets 44,743 (115) Decrease in deferred costs and other expenses 10,800 Decrease in other long-term assets 9 Increase (decrease) in accounts payable (20,061) 1,030 (2,337) Increase in accrued payroll and compensated absences 1,083 406 149 Increase in claims payable Increase in due to other governments Decrease in advances from other funds Increase (decrease) in deferred credits and other liabilities 7,046 (1,043) (2,620) Increase in customer deposits 1,388 424 224 Total adjustments 147,498 55,049 14,951 Net cash provided (used) by operating activities $ 400,901 118,003 25,894 The accompanying notes are an integral part of the financial statements. 32
City of Austin, Texas Exhibit C-3 (Continued) Governmental Nonmajor Activities-Enterprise 2002 Internal Service Funds Total Funds CASH FLOWS FROM INVESTING ACTIVITIES: Purchase of Investment securities (26,569) (516,388) Proceeds from sale and maturities of investment securities 26,541 541,175 Interest on investments 5,496 45,257 983 Net cash provided by investing activities 5,468 70,044 983 Net increase (decrease) in cash and cash equivalents (83,808) (49,349) 17,492 Cash and cash equivalents, October 1 196,509 568,643 55,509 Cash and cash equivalents, September 30 112,701 519,294 73,001 RECONCILIATION OF OPERATING INCOME TO NET CASH PROVIDED (USED) BY OPERATING ACTYTIES: Operating income (loss) (12,160) 315,140 1,389 Adjustments to reconcile operating income to net cash provided by operating activities: Depreciation 14,860 173,063 2,949 Amortization 2,500 Change in assets and liabilities: (Increase) in working capital advances (818) (Increase) decrease in accounts receivable (2,277) 16,220 (199) (Decrease) In allowance for doubtful accounts (60) (1,153) Decrease in receivable from other governments (743) (743) (Increase) decrease in inventory (23) (940) (433) (Increase) decrease in prepaid expenses and other assets (21) 44,607 58 Decrease in deferred costs and other expenses 10,800 Decrease In other long-term assets 9 Increase (decrease) in accounts payable 2,245 (19,123) (21) Increase in accrued payroll and compensated absences 1,260 2,898 498 Increase in claims payable 9,863 Increase In due to other governments 1,198 1,198 Decrease In advances from other funds 36 Increase (decrease) in deferred credits and other liabilities 615 3,998 56 Increase in customer deposits 321 2,357 Total adjustments 17,375 234,873 12,807 Net cash provided (used) by operating activities 5,215 550,013 14,196 The accompanying notes are an integral part of the financial statements. (Continued) 33
Proprietary Funds Statement of Cash Flows For the year ended September 30, 2002 (in thousands) Water and Electric Wastewater Airport NONCASH INVESTING, CAPITAL AND FINANCING ACTMTIES: Increase in advances from other funds $ - - - Increase (decrease) in deferred assetslexpenses (13,649) 13,836 Unamortized bond discounts, premiums, and issue costs on refunded bonds 20,729 (7,477) Increase (decrease) in capital appreciation bond interest payable 10,625 (6,955) Fixed assets contributed from (to) other funds 44 - Increase in contributed facilities - 9,698 Net increase (decrease) in the fair value of investments 6,860 (961) Amortization of bond discounts, premiums and issue costs (2,037) (916) (576) Amortization of deferred loss on refundings - (74) Gain (loss) on disposal of assets (2,251) 35 (56) Deferred costs recovered (16,557) (10,635) - Loss on extinguishment of debt (8,207) (8,036) Contributions from other funds Increase in deferred credits and other liabilities 213 27,413 Transfers from other funds The accompanying notes are an integral part of the financial statements. 34
City of Austin, Texas Exhibit C-3 (Continued) Governmental Nonmajor Activities-Enterprise 2002 Internal Service Funds Total Funds NONCASH INVESTING, CAPITAL AND FINANCING ACTIVmES: Increase in advances from other funds - - 44 Increase (decrease) in deferred assets/expenses - 187 (1) Unamortized bond discounts, premiums, and issue costs on refunded bonds - 13,252 - Increase (decrease) in capital appreciation bond interest payable - 3,670 Fixed assets contributed from (to) other funds 279 323 (6,434) Increase in contributed facilities - 9,698 Net increase (decrease) in the fair value of investments 223 6,122 - Amortization of bond discounts, premiums and issue costs (301) (3,830) (4) Amortization of deferred loss on refundings (559) (633) - Gain (loss) on disposal of assets (267) (2,539) (129) Deferred costs recovered - (27,192) - Loss on extinguishment of debt - (16,243) - Contributions from other funds - - 192 Increase in deferred credits and other liabilities - 27,626 - Transfers from other funds 2,109 2,109 The accompanying notes are an integral part of the financial statements. 35
Fiduciary Funds City of Austin, Texas Statement of Fiduciary Net Assets Exhibit D-1 September 30, 2002 (In thousands) Private Purpose Trust Agency ASSETS Pooled investments and cash $ 918 2,289 Due from other funds 150 - Other assets 121 _ Total assets 1,189 2,289 LIABILITIES Accounts payable 151 160 Due to other governments 1,400 Due to other funds 150 _ Deposits and other liabilities 215 729 Total liabilities 516 2,289 NET ASSETS Held in trust 673 Total net assets $ 673 The accompanying notes are an integral part of the financial statements. 36
Fiduciary Funds City of Austin, Texas Statement of Changes in Fiduciary Net Assets Exhibit D-2 For the year ended September 30, 2002 (In thousands) Private Purpose Trust ADDITIONS Contributions $ 215 Interest and other 33 Total additions 248 DEDUCTIONS Deductions 444 Total deductions 444 Change in net assets (196) Total net assets -beginning 869 Total net assets - ending $ 673 The accompanying notes are an integral part of the financial statements. 37
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) 1
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES The City of Austin, Texas (the City) is a municipal corporation incorporated under Article Xl, Section S of the Constitution of the State of Texas (Home Rule Amendment). The City operates under a Council-Manager form of government. The City Council is composed of a Mayor and six Councilmembers, all of whom are elected at large for three-year staggered terms, and who may serve for a maximum of two consecutive terms. A petition signed by 5% of the voters waives the term limit for a councilmember. The City's major activities or programs include public safety; transportation, planning and sustainability; public health; urban growth management; public recreation and culture; and general administrative services. In addition, the City owns and operates certain major enterprise activities, including an electric utility, water and wastewater utility, airport and other enterprise activities. These activities are included in the accompanying financial statements. The Charter of the City of Austin requires an annual audit by an independent certified public accountant. The financial statements of the City have been prepared in conformity with accounting principles generally accepted in the United States of America as applied to governmental entities. The Governmental Accounting Standards Board (GASB) is the accepted standard-setting body for establishing governmental accounting and financial reporting principles. The City has implemented GASB Statement No. 1 through Statement No. 38 and GASB Interpretation No. 6. The more significant accounting and reporting policies and practices used by the City are described below. As a local government, the City is exempt from federal income taxes, under Internal Revenue Code Section 115, and state sales tax. a - Reporting Entity As required by generally accepted accounting principles (GAAP), these financial statements present the City (the Primary Government) and its component units, entities for which the City is considered to be financially accountable. Blended component units, although legally separate entities are, in substance, part of the City's operations and so data from these units are combined with data of the City. Blended Component Units -- The Austin Housing Finance Corporation (AHFC) and Austin Industrial Development Corporation (AIDC) are legally separate entities from the City. AHFC and AIDC serve all the citizens of Austin and are governed by a board composed of the City Councilmembers. The activities are reported in the Housing Assistance Fund and Austin Industrial Development Corporation Fund, nonmajor special revenue funds. Related Organizations - The following entities are related organizations to which the City Council appoints board members, but for which the City has no significant financial accountability. The City appoints certain members of the board of the Capital Metropolitan Transit Authority (Capital Metro), but the City's accountability for this organization does not extend beyond making the appointments. City Councilmembers appoint themselves as members of the board of the Austin-Bergstrom International Airport (ABIA) Development Corporation; their function on this board is ministerial rather than substantive. The City Council appoints the members of the board of Austin-Bergstrom Landhost Enterprises, Inc., and Austin Convention Enterprises, Inc.; the functions of these boards are ministerial rather than substantive. These entities are separate from the operating activities of the City, i.e., the Airport (ABIA operations) and Convention Center. Related organizations are not included in the City s reporting entity. The City retirement plans (described in Note 8) and the City of Austin Deferred Compensation Plan for City employees are not included in the City s reporting entity because the City does not exercise substantial control over the entities. b - GASB Statement No. 34 and Related Statements In June 1999, the GASB issued Statement No. 34, Basic Financial Statements andManagements Discussion andAnalysis for State and Local Govemments. This statement, known as the 'New Reporting Model or as GASB 34, affects the preparation and presentation of the City s financial information. State and local governments have traditionally used a financial reporting model substantially different from the one used in private-sector financial reports' In addition, GASB Statement No. 37, Basic Financial Statements and Managements Discussion and Analysis for State and Local Govemments Omnibus, GASB Statement No. 38, Certain Financial Statement Note Disclosures and GASB Interpretation No. 6, Recognition and Measurement of Certain Liabilities and Expenditures in Governmental Financial Statements were required to be adopted concurrent with GASB Statement No. 34. The City adopted each of these standards as of October 1, 2001. 38
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) I
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued GASB 34 establishes new requirements and a new reporting model for the annual financial reports of state and local governments. The statement was developed to make governmental annual reports easier to understand and more useful to the people who use governmental information to make decisions. The primary effects of adoption of GASB 34 on the City s financial statements included the addition of managements discussion and analysis, the presentation of net assets, the use of accrual basis accounting in the govemment-wide financial statements, inclusion of required supplementary information, the elimination of the effect of internal service activities, recording of infrastructure assets and reflecting depreciation of capital assets in the government-wide statements. The new reporting model includes the following: Management s Discussion and Analysis - A narrative introduction and analytical overview of the City s financial activities, similar to the analyses provided in the annual reports of private sector organizations. Government-wide Financial Statements - New financial statements prepared using full accrual accounting for all of the City s activities. These statements include not only current assets and liabilities, but also governmental capital assets, other long-term assets and long-term liabilities. Full accrual accounting is used to report all revenues and costs of providing services each year, not just those received or paid in the current year or soon thereafter. Statement of Net Assets - This statement is designed to display the financial position of the primary government (governmental and business-type activities). The statement includes current and long-term assets and liabilities, including infrastructure assets. The net assets of the City are classified into three categories: (1) invested in capital assets, net of related debt; (2) restricted; and (3) unrestricted. Statement of Activities - This statement reports expenses and revenues on an accrual basis, and in a format that focuses on the cost of the City s functions. Fund Financial Statements - Fund financial statements focus on funds. Governmental funds are reported using the current financial resources measurement focus and the modified basis of accounting. Proprietary funds are reported on the economic resources measurement focus and the accrual basis of accounting. Notes to Basic Financial Statements - The notes to the financial statements provide additional information that is essential to a full understanding of the data provided in the govemment-wide and fund financial statements. Required Supplementary Information (RSI) - The City adopts an annual appropriated budget for the General Fund. The RSI provides a comparison to budget and is provided to demonstrate compliance with this budget. Government-wide and Fund Financial Statements - The basic financial statements include both government-wide and fund financial statements. The previous financial reporting model emphasized fund types, i.e., the total of all funds of a particular type, such as capital projects funds. The new reporting model focus is on either the City as a whole or on major individual funds, as defined by GASB 34. The government-wide financial statements (i.e., the statement of net assets and the statement of activities) report information on all of the non-fiduciary activities of the primary government and its component units. Internal service fund asset and liability balances that are not eliminated in the statement of net assets are reported in the governmental activities column on the government-wide statements. Governmental activities, which normally are supported by taxes and intergovernmental revenues, are reported separately from business-type activities, which rely to a significant extent on fees and charges for support. The statement of net assets includes governmental assets and liabilities previously reported in the General Fixed Asset Account Group and the General Long-Term Debt Account Group, in addition to infrastructure assets. The statement of activities demonstrates the degree to which the direct expenses of a function or segment are offset by program revenues. Direct expenses are those that are clearly identifiable with a specific function or segment. Certain indirect costs are included in the program expenses of most business-type activities. Program revenues include 1) charges to customers who purchase, use or directly benefit from goods, services or privileges provided by a given function or segment and 2) grants and contributions that are restricted to meeting the operational or capital requirements of a particular function or segment. Taxes and other items not properly included among program revenues are reported as general revenues. The fund level statements focus on the governmental, proprietary and fiduciary funds. The accounts of the City are organized on the basis of funds. Each fund was established for the purpose of accounting for specific activities in accordance with applicable regulations, restrictions or limitations. Major individual governmental funds and major individual enterprise funds are reported as separate columns in the fund financial statements. 39
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) I
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued The City s fiduciary funds, which have been redefined and narrowed in scope, are presented in the fund financial statements by type (private purpose and agency). By definition these assets are held for the benefit of a third party, and cannot be used to address activities or obligations of the government, and are therefore not included in the government-wide statements. Reconciliation of the fund financial statements to the govemment-wide financial statements is provided in the financial statements to explain the differences created by the integrated approach of GASB 34. c - Measurement Focus, Basis of Accounting and Financial Statement Presentation The government-wide financial statements are reported using the flow of economic resources measurement focus and the accrual basis of accounting. Revenues are recorded when earned and expenses are recorded when a liability is incurred, regardless of the timing of related cash flows. Property taxes are recognized as revenues in the year for which they are levied. Grants and similar items are recognized as revenues as soon as all eligibility requirements have been met. Governmental fund financial statements are reported using the current financial resources measurement focus and the modified accrual basis of accounting. This basis of accounting recognizes revenues in the accounting period in which they become susceptible to accrual, i.e. both measurable and available. Revenues, other than grants, are considered to be available when they are collectible within the current period or soon enough thereafter to pay liabilities of the current period (defined by the City as collected within 60 days of year end). Revenues billed under a contractual agreement with another governmental entity, including federal and state grants, are recognized when billed and when all eligibility requirements of the provider have been met and are considered to be available if expected to be collected within one year. Expenditures generally are recorded when a liability is incurred. However, expenditures related to compensated absences and arbitrage are recorded when the liability is matured. Debt service expenditures are recognized when payment is matured. The reported fund balance of governmental funds is considered a measure of available spendable resources. Property taxes, sales taxes, franchise taxes, EMS charges, Municipal Court fines and interest associated with the current fiscal period are all considered to be susceptible to accrual and so have been recognized as revenues of the current fiscal period. All other revenue items are considered to be measurable and available only when cash is received by the City. The City reports the following major governmental fund: General Fund: The primary operating fund of the City. It is used to account for all financial resources, except those required to be accounted for in another fund. It includes the following activities: public safety; transportation, planning and sustainability; public health; public recreation and culture; urban growth management; and general government. Proprietary and fiduciary fund financial statements are accounted for on the economic resources measurement focus and the accrual basis of accounting. Proprietary funds distinguish operating revenues and expenses from nonoperating items. Operating revenues and expenses generally result from providing services in connection with a proprietary fund s principal ongoing operations, such as providing electric or water-wastewater services. Other revenues or expenses are nonoperating items. The City reports the following major enterprise funds: Electric Fund: Accounts for the activites of the City-owned electric utility, doing business as Austin Energy Water and Wastewater Fund: Accounts for the activities of the City-owned water and wastewater utility. Airport Fund: Accounts for the operations of the Austin-Bergstrom Intemational Airport (ABIA). 40
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) I
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued In addition, the City reports the following nonmajor governmental funds: Special Revenue Funds account for the proceeds of specific revenue sources that are legally restricted to expenditures for specified purposes, including grant funds. Debt Service Funds account for the accumulation of resources for, and the payment of, general long-term debt and HUD Section 108 loan principal, interest and related costs. Capital Projects Funds account for financial resources for the acquisition or construction of major capital facilities (other than those reported within proprietary funds and private purpose funds) and funded primarily by general obligation debt, other tax supported debt, interest income and other intergovernmental revenues. A 1981 ordinance requires the establishment of a separate fund for each bond proposition approved in each bond election. Permanent Funds account for resources that are legally restricted to the extent that only earnings and not principal may be used for purposes that support the City s programs. Permanent funds account for the public recreation and culture activity. The City reports the following proprietary and fiduciary funds: Enterprise Funds account for operations that are financed and operated in a manner similar to private business enterprises. Costs are financed or recovered primarily through user charges. The City has elected to follow GASB statements issued after November 30, 1989, rather than statements issued by the Financial Accounting Standards Board (FASB), in accordance with GASB Statement No. 20. The nonmajor enterprise funds account for the operations in a variety of areas: convention center, drainage, golf, hospital, recreation activities, primary care clinics, solid waste and transportation. Internal Service Funds account for the financing of goods or services provided by one City department or agency to other City departments or agencies or to other governmental units on a cost-reimbursement basis. These activities include, but are not limited to, capital projects management, employee health benefits, fleet services, information services, liability reserve (city-wide self insurance) services, supportive services, wireless communication services and workers compensation coverage. Fiduciary Funds account for assets held by the City in a trustee capacity or as an agent for Individuals, private organizations or other governments: Private-purpose trust funds account for all other trust arrangements under which principal and income benefit individuals, private organizations or other governments. Private-purpose trust funds account for various purposes: general government, transportation, public recreation and culture and urban growth management. Agency funds account for net assets held on behalf of others and are purely custodial (assets equal liabilities). d - Budget The City Manager submits a proposed budget to City Council no later than thirty days prior to the beginning of the new fiscal year. The City Council holds public hearings, modifies the City Managers recommendations, and adopts a final budget no later than the twenty-seventh day of September. The City Council passes an appropriation ordinance and a tax levying ordinance. Annual budgets are legally adopted for the General Fund, certain special revenue funds and debt service funds. Annual budgets are adopted for enterprise and internal service funds, although they are not legally required. Multi-year budgets are adopted for capital projects and grant funds, where appropriations remain authorized for the life of the project, irrespective of fiscal year. Expenditures are appropriated on a modified accrual basis, except that commitments related to purchase orders are treated as expenditures in the year of commitment. Certain charges to ending fund balance are budgeted as nondepartmental expenditures. 41
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Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) 1
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued Formal budgetary control is employed during the year at the fund and department level as a management control device for annually budgeted funds. Budgets are modified throughout the year. The City Manager is authorized to transfer appropriation balances within a fund and department of the City. The City Council must approve amendments to the budget and transfers of appropriations from one fund and department to another. The original and final budgets for the General Fund are reported in the required supplementary information. Unencumbered appropriations for annual budgets lapse at fiscal year end. During fiscal year 2002, the following nonmajor governmental funds exceeded their legally adopted expenditure or transfer budget (in thousands): EMS Travis County Reimbursed ($79) and Wildland Conservation ($4). e - Financial Statement Elements Pooled Investments and Cash - Cash balances of all City funds (except for certain funds shown in Note 5 as having non-pooled investments) are pooled and invested. Investments purchased with pooled cash, consisting primarily of U.S. government obligations and U.S. agency obligations, are stated at fair value. Interest earned on investments purchased with pooled cash is allocated monthly to each participating fund based upon the fund's average daily balance. Funds that incur a negative balance in pooled cash and investments are not allocated interest earnings nor charged interest expense. Investments - Certain investments are required to be reported at fair value, based on quoted market prices. Realized gains or losses resulting from the sale of investments are determined by the specific cost of the securities sold. The City carries all of its investments in U.S. government and agency debt securities and money market mutual funds at fair value as of September 30, 2002. Investments in local government investment pools are carried at amortized cost, which approximates fair value. Accounts Receivables -- Balances of accounts receivables, reported on the government-wide statement of net assets, are aggregations of different components such as charges for services, fines, and balances due from taxpayers or other governments. In order to assist the reader, the following information has been provided regarding significant components of receivables balances as of September 30, 2002 (inthousands): Other Charges for Govem-Services Fines Taxes ments Total Governmental activities General Fund $ 46,035 54,500 25,428 434 126,397 Nonmacor governmental funds 929 45 6,872 8,415 16,261 Intemal service funds 742 - - - 742 Allowance for doubtful accounts (43,924) (35,952) _ - (79,876) Total $ 3,782 18,593 32,300 8,849 63,524 Municipal Court fines in the governmental activities, because of the nature of the fines, have a collection period greater than one year. Fines recognized that will not be collected during the subsequent year are estimated to be approximately $8.5 million. Business-type activities are primarily comprised of charges for services. Elimination of Internal Activities - The elimination of internal service fund activity is needed in order to eliminate duplicate activity in making the transition from the fund level financial statements to the government-wide financial statements. In addition, the elimination of internal service fund activity requires the City to 'look back and adjust the internal service funds internal charges. A positive change in net assets derived from internal service fund activity results in a pro rata reduction in the charges made to the participatory funds. A deficit change in net assets of internal service funds requires a pro rata increase in the amounts charged to the participatory funds. Internal Balances - In the government-wide statement of net assets, internal balances are the receivables and payables between the governmental and business-type activities. 42
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) 1
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued Interfund Activities - In the government-wide statement of activities, the effect of interfund activity has generally been removed from the statements. Exceptions include the chargeback of services, such as utilities or vehicle maintenance, and charges for central administrative costs. Elimination of these charges would distort the direct costs and program revenues of the various functions reported. The City recovers indirect costs that are incurred in the Support Services Fund, which is reported as an internal service fund. Indirect costs are calculated in a city-wide cost allocation plan or through indirect cost rates. These amounts are eliminated in the govemment-wide statement of activities. Interfund Receivables, Payables - During the course of operations, numerous transactions occur between individual funds for goods provided or services rendered. These receivables and payables are classified as 'due from other funds or 'due to other funds on the fund-level statements when they are expected to be liquidated within one year. If receivables or payables are expected to be liquidated after one year, they are classified as 'advances to other funds or 'advances from other funds. Inventories - Inventories are valued at cost, which is determined as follows: Fund Inventory Valuation Method General Fund Average cost (predominantly); some first-in, first-out Electric: Fuel oil and coal Last-in, first out Other inventories Average cost All others Average cost Inventories for all funds use the consumption method and expenditures are recorded when issued. Inventories reported in the General Fund and certain special revenue funds are offset by a fund balance reserve, which indicates that they do not represent 'available spendable resources.' Prepaid expenses and other assets - The governmental activities statement of net assets includes prepaid expenses and other assets. Fund balance is reserved for prepaid expenses; fund balance is not reserved for other assets. Restricted assets - Restricted assets are assets whose use is subject to constraints that are either (a) externally imposed by creditors (such as through debt covenants), grantors, contributors, or laws or regulations of other governments or (b) imposed by law through constitutional provisions or enabling legislation. The balance of restricted assets accounts in the enterprise funds are as follows (in thousands): Business-type Activities Water and Total Restricted Electric Wastewater Airport Nonmajor Assets Debt service $ 70,177 36,003 13,798 6,036 126,014 Bond reserve 64,394 45,531 - 6,864 116,789 Capital projects 23,286 59,285 67,813 63,993 214,377 Nuclear decommissioning 81,727 - - - 81,727 Nuclear fuel inventory replacement 33,234 - - - 33,234 Customer and escrow deposits 5,508 1,559 28,294 4,549 39,910 Federal grants - - 4,142 - 4,142
$ 278,326 142,378 114,047 81,442 616,193 43
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) 1
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued Capital assets - Capital assets, which include land, facilities and improvements, machinery and equipment and infrastructure assets, are reported in the applicable governmental or business-type activity columns of the government-wide statement of net assets, and related depreciation is allocated to programs in the statement of activities. Capital assets are defined as assets with an initial individual cost of $1,000 or more and an estimated useful life of greater than one year. Assets purchased or constructed are capitalized at historical cost. Contributed or annexed capital assets are recorded at estimated fair market value at the time received, or at historical cost, if historical cost is available. Capital outlay is recorded as an expenditure in the General Fund and other governmental funds, and as an asset in the government-wide financial statements and proprietary funds. Maintenance and repairs are charged to operations as incurred, and improvements and betterments that extend the useful lives of capital assets are capitalized. The City obtains public domain capital assets (infrastructure) through capital improvement projects (CIP) construction, or through annexation or developer contribution. Infrastructure consists of certain improvements other than buildings, including streets and roads, bridges, pedestrian facilities, drainage systems and traffic signal systems. Interest is not capitalized on governmental capital assets. For enterprise funds, interest paid on long-tern debt in the enterprise funds is capitalized when it can be attributed to a specific project and when it materially exceeds the interest revenue generated by the bond proceeds issued to fund the project. Capital assets are depreciated using the straight-line method over the following estimated useful lives (in years): Business-type Actvites Governmental Water and Nonmajor Assets Activities(1) Electric Wastewater Airport Enterprise Buildings 40 30 40-50 40 40 Equipment 12-15 12-40 12-40 10-12 7-40 Vehicles 3-15 3-15 3-15 3-15 3-15 Improvements to grounds 15 30 40-50 15 15 Communication equipment 7 7 7 7 7 Fumiture and fixtures 12 12 12 12 12 Computers and EDP equipment 7 7 7 7 7 Infrastructure Streets and roads 30 Bridges 50 Drainage systems 50 Pedestrian facilities 20 Traffic signals 25 (1) Includes internal service funds Depreciation of assets is classified by functional components. The City considers library collections, art treasures and land to be inexhaustible; and therefore, these assets are reported as nondepreciable. The true value of library collections and art treasures is expected to be maintained over time and, thus, not depreciated. Unallocated depreciation reported in the government-wide statement of activities consists of depreciation of infrastructure assets ($34.1 million). In the government-wide and proprietary fund statements, the City recognizes a gain or loss on the disposal of assets when it retires or otherwise disposes of capital assets (other than debt-financed assets of the utility funds, where the gain or loss is deferred in accordance with FASB Statement No. 71). Intangible Assets - Proprietary Funds - Intangible assets include the amortized cost of a $100 million contract between the City and the Lower Colorado River Authority (LCRA) for a fifty-year assured water supply agreement, with an option to extend another fifty years. The City and LCRA entered into the contract in 1999, and the asset is being amortized over 40 years. 44
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) I
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued Deferred Expenses or Credits - The City s utility systems are reported in accordance with Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Certain utility expenses that do not currently require funds are deferred to future periods in which they are intended to be recovered by rates. Likewise, certain credits to income are deferred to periods in which they are matched with related costs. These expenses or credits include changes in fair value of investments, contributions and gain or loss on disposition of debt-financed assets. Deferred expenses will be recovered in these future periods by setting rates sufficient to provide funds for the related debt service requirements. If rates being charged will not recover deferred expenses, the deferred expenses will be subject to write off. Retail deregulation of electric rates in the future may affect the Citys current accounting treatment of its electric utility revenues, expenses and deferred amounts. Compensated Absences - The amounts owed to employees for unpaid vacation and sick leave liabilities, including the City's share of employment-related taxes. The liabilities and expenses are reported on the accrual basis of accounting in the applicable governmental or business-type activity columns of the government-wide statements, and in the enterprise activities of the fund financial statements. The liabilities and expenditures are reported on the modified accrual basis in the governmental fund financial statements; the estimated liability for governmental funds is the amount of sick and vacation paid at termination within 60 days of year-end. City policies provide for the following amounts to be paid at termination: accumulated vacation pay with a maximum of six weeks and accumulated sick leave with a maximum of ninety days. Sick leave accumulated in excess of ninety days or by employees hired on or after October 1, 1986 is not payable at termination, and is not included inthese financial statements. Long-Term Debt - The debt service for general obligation bonds and other general obligation debt, including loans, issued to fund general government capital projects is paid from tax revenues, interfund transfers and intergovernmental revenues. Such general obligation debt is reported in the govemment-wide statements under governmental activities. The debt service for general obligation bonds and other general obligation debt issued to fund proprietary fund capital projects is normally paid from net revenues of the applicable proprietary fund, although such debt will be repaid from tax revenues if necessary. Such general obligation debt is shown as a specific liability of the applicable proprietary fund, which is appropriate under generally accepted accounting principles and in view of the expectation that the proprietary fund will provide resources to service the debt. Revenue bonds that have been issued to finance capital projects of certain enterprise funds are to be repaid from net revenues of these funds. Such debt is recorded in the funds. Operating revenues and interest income that are used as security for revenue bonds are reported separately from other revenues. The City defers and amortizes gains or losses realized by proprietary funds on refundings of debt and for governmental activities in the government-wide financial statements, and reports both the new debt liability and the related deferred amount on the funds' balance sheets. The City recognizes gains or losses on debt defeasance when funds from current operations are used. Other Long-Term Liabilities - Capital appreciation bonds are recorded at net accreted value. Annual accretion of the bonds is recorded as interest expense during the life of the bonds. The cumulative accretion of capital appreciation bonds, net of interest payments on the bonds, Is recorded as capital appreciation bond interest payable. Landfill Closure and Postclosure Care Costs - The City reports municipal solid waste landfill costs in accordance with GASB Statement No. 18, Accounting for Municipal Solid Waste Landfill Closure and Postclosure Care Costs. The liability for landfill closure and postclosure costs is reported in the Solid Waste Services Fund, a nonmajor enterprise fund. Operating Revenues - Revenues are recorded net of allowances, including bad debt, in the government-wide and proprietary fund-level statements. The funds listed below reduced revenues by allowances, as follows (in thousands): Electric Fund $ 10,125 Water and Wastewater Fund 1,112 Non-major Enterprise Funds 1,678 45
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) I
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued Interfund Revenues, Expenses and Transfers - Transactions between funds that would be treated as revenues, expenditures, or expenses if they involved organizations external to the governmental unit are accounted for as revenues, expenditures, or expenses in the funds involved, such as billing for utility services. Transactions between funds that constitute reimbursements for expenditures or expenses are recorded as expenditures or expenses in the reimbursing fund and as reductions of the expenditure or expense in the fund that is reimbursed. Transfers between funds are reported in the operations of governmental and proprietary funds. Intergovernmental Revenues, Receivables and Liabilities - Intergovernmental revenues and related receivables arise primarily through funding received from Federal and State grants. These revenues and receivables are earned through expenditure of money for grant purposes. Intergovernmental liabilities arise primarily from funds held in an agency capacity for other local governmental units. Federal and State Grants, Entitlements and Shared Revenues - Grants, entitlements and shared revenues may be accounted for within any City fund. The purpose and requirements of each grant, entitlement, or shared revenue are analyzed to determine the appropriate fund statement and revenue category in which to report the related transactions. Grants, entitlements and shared revenues received for activities normally recorded in a particular fund may be accounted for in that fund, provided that applicable legal restrictions can be satisfied. Revenues received for activities normally recorded in other governmental funds are accounted for within the nonmajor governmental fund groupings: Federal grant funds, State grant funds, and other special revenue grant funds. Capital grants restricted for capital acquisitions or construction, other than those associated with proprietary type funds, are accounted for in the applicable capital projects funds. Revenues received for operating activities of proprietary funds or revenues that may be used for either operations or capital expenditures at the discretion of the City are recognized in the applicable proprietary fund. Restricted Resources - When both restricted and unrestricted resources are available for use, it is the Citys policy to use restricted resources first, and then unrestricted resources as they are needed. Special Items - These are significant transactions or events within the control of the City that are either unusual in nature or infrequent in occurrence. In 2002, the City purchased from Computer Sciences Corporation (CSC) for $4 million the right to develop a City-owned block. Under an earlier agreement, CSC had the right to develop the block by 2015. Reservations of Fund Equity - Reservaton of fund balances of the governmental funds indicate that portion of fund equity which is not available for appropriation for expenditure or is legally restricted by outside parties for use for a specific purpose. Designations of fund balance are the representations of management for the utilization of resources in future periods. Cash and Cash Equivalents - For purposes of the statement of cash flows, the City considers cash and cash equivalents to be currency on hand, cash held by trustee, demand deposits with banks, and all amounts included in pooled investments and cash accounts. Pension Costs - It is the policy of the City to fund pension costs annually. Pension costs are composed of normal cost and, where applicable, amortization of unfunded actuarial accrued liability and of unfunded prior service cost (see Note 8). Risk Management - The City is exposed to employee-related risks for health benefits and workers compensation, as well as to various risks of loss related to torts, including medical malpractice; theft of, damage to, or destruction of assets; errors and omissions; and natural disasters. The City continues to be self-insured for liabilities for most health benefits, third-party and workers compensation claims. The City purchases commercial insurance for coverage for property loss or damage, commercial crime, fidelity bonds, and airport operations. In addition, the City purchases a broad range of insurance coverage for contractors working at selected capital improvement project sites. The City does not participate in a risk pool. The City complies with GASB Statement 10, Accounting and Reporting for Risk Financing and Related Insurance Issues (see Note 16). f - Comparative Data Governments are required to present comparative data only in connection with Managements Discussion and Analysis (MD&A). They may also present comparative data on the government-wide statement of activities. In this first year of GASB Statement No. 34 implementation, comparative data is not required and is not presented. 46
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) I
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES, continued g - Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management .to make estimates and assumptions that affect the financial statements and the reported amounts of revenues and expenditures during the reporting period. Actual results could differ from those estimates. 2 RECONCILIATION OF GOVERNMENT-WIDE AND FUND FINANCIAL STATEMENTS a - Explanation of differences between the governmental fund balance sheet and the government-wide statement of net assets Total fund balances of the City s governmental funds, $383 million, differ from the net assets of governmental activities, $1,247 million, reported in the statement of net assets. The differences result from the long-term economic focus in the government-wide statement of net assets versus the current financial resources focus of the governmental fund balance sheets. The differences are shown below (in thousands): Total fund balances - Governmental funds $ 383,405 Amounts reported for governmental activities in the statement of net assets are different because: Capital assets used in governmental activities are not financial resources and therefore are not reported in the funds. Governmental capital assets 2,139,354 Less: accumulated depreciation (483,118) Total 1,656,236 Other-long term assets are not available as current-period resources and are not reported in the funds. Accounts and other taxes receivable 18,285 Deferred revenue - Property taxeslinterest 8,768 Deferred costs and expenses 870 Total 27,923 Long-term liabilities are not payable in the current period and are not reported In the funds. Bonds and other tax supported debt payable, net (778,480) Compensated absences (56,711) Interest payable (4,244) Deferred credits and other liabilities (18,540) Total (857,975) Internal service funds 37,848 Total net assets - Governmental activities $ 1,247,437 47
Notes to Basic Financial Statements City of Austin, Texas September 30, 2002 (Continued) 2 RECONCILIATION OF GOVERNMENT-WIDE AND FUND FINANCIAL STATEMENTS, continued b - Explanation of differences between the governmental fund statement of revenues, expenditures, and changes in fund balances and the government-wide statement of activities The net change in fund balances of governmental funds, $151.6 million, differs from the change in net assets for governmental activities, $42.5 million, reported in the statement of activities. The differences result from the long-term economic focus in the government-wide statement of net assets versus the current financial resources focus of the governmental fund balance sheets. The differences are shown below (in thousands): Net change Infund balances - Govemmental funds $ 151,609 Governmental funds report capital outlay as expenditures. In the statement of activities, the cost of those assets are depredated over the estimated useful life of the asset Capital outlay 164,523 Depredation expense (58,101) Loss on disposal of capital assets (7,891) Total 98,531 Revenues in the statement of activities that do not provide current available financial resources are not reported as revenues in the funds. Property taxes 8,068 Charges for services 8,116}}