ML031430458
| ML031430458 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/16/2003 |
| From: | Jack Giessner Indiana Michigan Power Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| AEP: NRC:3071-02 | |
| Download: ML031430458 (184) | |
Text
Indiana Michigan Power Company 500 Circle Drive Buchanan, MI 49107 1395 INDIANA MICHIGAN POWER May 16, 2003 AEP:NRC:3071-02 10 CFR 50.71(b) 10 CFR 140.21(e)
Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P1-17 Washington, D.C. 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 2002 FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY In accordance with 10 CFR 50.71(b), Attachment 1 to this letter provides the Indiana Michigan Power Company (I&M) 2002 Annual Financial Report. This report is also available electronically at http://aep.com/investors/edgar/docs/lOK-2-C-2002-final.pdf. provides a copy of the year 2003 projected cash flow for I&M as required by 10 CFR 140.2 1(e).
This letter contains no new commitments.
Should you have any questions, please contact Mr. Brian A. Mclntrye, Manager of Regulatory Affairs, at (269) 697-5806.
- Since, ir or, Technical Projects DB/rdw Attachments c:
H. K. Chernoff, NRC Washington, DC K. D. Curry, Ft. Wayne AEP, w/o attachments J. E. Dyer, NRC Region III J. T. King, MPSC, w/o attachments MDEQ - DW & RPD, w/o attachments NRC Resident Inspector J. F. Stang, JR., NRC Washington, DC
U. S. Nuclear Regulatory Commission AEP:NRC:3071-02 Page 2 bc:
A. C. Bakken III, w/o attachments M. J. Finissi, w/o attachments J. B. Giessner D. W. Jenkins, w/o attachments J. A. Kobyra, w/o attachments B. A. McIntyre, w/o attachments J. E. Newmiller J. E. Pollock, w/o attachments D. J. Poupard M. K. Scarpello, w/o attachments T. K. Woods, w/o attachments
ATTACHMENT 1 TO AEP:NRC:3071-02 INDLANA MICHIGAN POWER COMPANY 2002 ANNUAL REPORT Sections B through F and Sections H through K have been omitted from this attachment in order to provide only information relevant to the Licensee, Indiana Michigan Power Company.
- ~ ~
~
~~~-
its..
2002 Annual Reports American Electric;Power,Company, A
AL (enerating :Company AEP Texas Central Company AEP Texas North Company Appalachian Power Com'pany Inc.
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 B;-AMERICAN 0
8 ~~~~~~~ELECTRIC-POWER f-PAimerica's Ener a'artnzer-I
Contents Page Glossary of Terms Forward Looking Informatio'n
'0 iv AEP Common Stock and Dividend Inforrnation v
American Electric Power Company, Inc. an'd Subsidiary Cormpanies
'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 3
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-16 1Independent Auditors' Report A-17 Management's Responsibility A-18 AEP-Generating Company Selected Financial Data Management's'Narrative Analysis of Results of Operations Statements of Income and Statements of Retained Earnings Balance Sheets Statements of Cash Flows Statements of Capitalization Index to Cornbined Notes to Financial Statements Indeppndent Auditors' Report' AEP Texas Central Company and Subsidiaries Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations Consolidated Statements of Income and Consolidated Statements of Comprehensive Income Consolidated Statements of Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt, Index toCombined Notes to Consolidated Financial Statements Independent Auditors' Report
'AEP Texas North Company Selected Financial Data Management's Narrative Analysis of Results of Operations Statements of Operations and Statements of Comprehensive Income Statements of Retained Earnings Balance Sheets Statements of Cash Flows Statements of Capitalization Schedule of Long-term Debt Index to Combined Notes to Financial Statements
- -Independent Auditors' Report B-1 I B-2
- B-3 B-6 B-7 B-8 B-9 C-1 C-2 C-5 C-6 C-7 C-9 C-10 C-11 C-13 C-14 D-1 D-2 D-4 D-5 D-6 D-8 D-9 D-1 0 D-1 D-12 I
I
Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations Consolidated Statements of Income and Consolidated Statements of Comprehensive Income Consolidated Statements of Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt Index to Combined Notes to Consolidated Financial Statements Independent Auditors' Report Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data Management's Narrative Analysis of Results of Operations Consolidated Statements of income and Consolidated Statements of Comprehensive Income Consolidated Statements of Retained Earnings CQnsolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt Index to Combined Notes to Consolidated Financial Statements Independent Auditors' Report Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations Consolidated Statements of Income and Consolidated Statements of Comprehensive Income Consolidated Statements of Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt Index to Combined Notes to Consolidated Financial Statements Independent Auditors' Report Kentucky Power Company Selected Financial Data Management's Narrative Analysis of Results of Operations Statements of Income, Statements of Comprehensive Income and Statements of Retained Earnings Balance Sheets Statements of Cash Flows Statements of Capitalization Schedule of Long-term Debt Index to Combined Notes to Financial Statements Independent Auditors' Report 1~
id I
E-2 E-5' E-6 E-7' E-9 E-1 0 E-1l1 E-1 2 E-1 3 F-I F-2 F-4 F-5 F-6 F-9.
F-b F-1li F-i 2 G-1 G-2 G-5
.G-6 G-7 G-9
- G-10 G-11 G-12 G-13 H-1 H-2 HA
. H-5 H-7 H-8 H-9 H-1 0 H-11
- i
Ohio Power Company Selected Financial Data Management's Discussion and Analysis of Results of Operation Statements of Income and Statements of Comprehensive Income Statements of Retained Earnings Balance Sheets Statements of Cash Flows Statements of Capitalization Schedule of Long-term Debt Index to'Combined Notes'to Financial Statements Independent Auditors'. Report Public Service Company of Oklahoma and Subsidiary Selected Consolidated Financial Data Management's Narrative Analysis of Results of,Operations Consolidated Statements of Income and Consolidated Statements of Comprehensive Income Consolidated Statements of Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt Index to Combined Notes to Consolidated Financial Statements Independent Auditors' Report Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data
'Management's Discussion and Analysis of Results of Operations Consolidated Statements of Income'and Consolidated Statements of Comprehensive Income Consolidated Statements of Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization,,
Scheduleof Long-term Debt Index to Combined Notes to Consolidated Financial Statements Independent Auditors' Report Combined Notes to Financial Statements Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters 1-2 1-6 1-7
.1-9 1-10 1-12 1-12 1-1 J-2 J-4 J-5 J-6 J-8 J-9 J-1 0:
J-l J-12 K-1 K-2 K-4 K-5 K-6 K-8 K-9
(-10 K-11
(-12 L-1 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 Meaninq 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 for funds 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.
FERC....
Federal Energy Regulatory Commission.
-n FM B...
is oaeBn.
F...
First Mortgage Bond.-.
FUCOs...
Foreign Utility Companies.-
GAAP...
Generally Accepted Accounting Principles.
I&M
.Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR.I nterchange Cost Reconstruction..
.Installment Purchase Contract.
IRS
.Internal Revenue Service._.
IURC.I Indiana Utility Regulatory Commission.
ISO.I ndependent 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.....
Th e Ohio Electric Restructuring Act of 1999.
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 byAEGCo and l&M.
RTO.Regional Transmission Organization.
.- ~~ ~ ~
~
~~~~~~~~~~~~~~~~~~~~~~
- i.
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 TvDes of Regulation.
SFAS 101.............
Statement of Financial Accounting Standards No. 101, Accounting for the 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 State Corporation Commission.
WV........
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 by AEP and its registrant subsidiaries contain forward-looking statemnents within the meaning of.
Section 21E 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 esults to differ materially from those in the forward-looking statements are:
- Electric load and customer growth.
- Abnorm'al weather conditions.
- Available sources and costs of els.,
- Availability of generating capacity.
- The speed and degree to which competition is itroducdtou sricetriois
- 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 articipants.
- 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 adgas market prices.
- Interest rates;'
- Liquidity in the banking, c-apital 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 December 2002 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
- S I
p
-This page intentionally left blank.-
AMERICAN ELECTRIC POWER COMPANY, INC. AND. SUBSIDIARY.COMPANIES selected consolidated Financial Data
- Year Ended December 31.
.2002
-2001 2000 1999 OPERATIONS STATEMENTS DATA (in-millions):-
Total Revenues
$14,555
$12,767
$11,113
$10,019
$1 Operating Income 1,263 2,182 1
,774 2,061 Income Before Discontinued Operations, Extraordinary Items and cumulative Effect.
21 917 180 869 Discontinued operations:Income (Loss)
(190) 86' 122 117 Extraordinary Losses (50)
(35)
(14)
Cumulative Effect of, Accounting change-Gain (Loss)
'(350) 18 Net Income (Loss)
(519).
971 267 972 December 31.
- 2002 2001 2000 1999 BALANCE SHEET DATA-(in millions):_
Property, Plant and Equipment
$37,857
$37,414
$34,895
$33,930
$3 Accumulated Depreciation and Amortization' 16.173 15.310 14,899 14266 Net Property,
'Plant and Equipment j,2BA
- $2104
- $19,99 6
Total Assets
$34,741
$39,297
$46,633
$35,296
$3 L998 4,080 2,046
.859 116 975 L998 -
32,400 i 3.374 3,418 Common Shareholde!rs' Equity
- 7,064 +r- -8,229 cumulative Preferred stocks of Subsidiaries*
Trust Preferred Securities
.Long-term Debt*
obligations under Capital Leases*
-Year Ended December 31.
COMMON STOCK DATA:
Earnings per Common Share:
Before Discontinued operations, Extraordinary Items and-Cumulative Effect
-Discontinued operations
Extraordinary Losses cumulative Effect of, Accounting change Earnings'(Loss)Per share
-8,054
. 145 :
156 321 10,496
- 321,
.9,505 228 - ;
- 451 -
2002 0.06 (0.57)
U.
- 06)
' 8,673 182 334
' 335 8,980 9,471 I ~'
614 610 2001 2000 1999 I,.
$ -2.85 0.26
- ---,(0.16)
. $ 0.56 0.38-
- .: (0.11)
$ 2.71 0.36
- (0.04)
' 0.06 LiZ )
- 3.
I Average Number of shares Outstanding (in millions)
Market Price Range:
ig
-- 0
~~~High Low V:.
Yer-end Markeot Pe-
.;r~
332 322
$ 48.80
$51.20 15.10 39.25 r -,
' 2~~~7.3 :
-0435
- _ 322,
$48-15/16
, 25-15/16 4R-l i7
, - 321
$48-3/1E 30-9/16 3-1
/R Cash Dividends on Common**
2.40
$2.40
$2.40-:
$2.40 Dividend Payout Ratio**'
(152.9)%
-, 79.7%
i289.2%
-f 79.2%
-:Book value.per Share.
$20.85.
$25.54
'$25.01
$26.96
- Including portion due within 'one year.
Long-term Debt'includes Equity Unit Senior'Notes.
B**ased on AEP historical dividend rate.
see "common stock and Dividend Irformation" (on page v) re potential reduction of future dividends.
A-1 318
$53-5/16 42-1/16 47-1/16
- I.$2.40 I
78.4%
'$26.46 egarding the 8,452 350 335 9,215 539 1998
$2.70 0.36 7 -
. -1 q
i-bi- -
.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Mana-gement's Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S.
We provide generation, transmission and distribution service to almost five million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana,
- Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies.
We have a vast portfolio of assets including:
38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in our market areas 4,000 megawatts of generating capacity in the U.K., a countrywhich is currently experiencing excess generation capacity 38,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S.
186,000 miles of distribution lines that support delivery of electricity to our customers' premises Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity) 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of gas storage facilities Business Strategy We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets.
We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business.
Through our utility operations focus, we intend to be the energy and low cost generation provider of choice.
We have ample generation to meet our customers' needs.
We have a cost advantage resulting from AEP's long tradition of designing, building and operating efficient power plants and delivery networks. Our customers continue to show top quartile level of satisfaction. We provide safe and reliable sources of energy.
Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors.
We are addressing many challenges in our unregulated business.
We have already substantially reduced our trading activities.
We have written down the value of several investments to reflect deterioration in market conditions. We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy.
We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling.
Transition rules for Michigan and Virginia do not require legal separation. Deregulation is no longer an expectation in the foreseeable future in the other states where we operate.
Our strategy for the core business of utility operations is to:
Maintain moderate but steady earnings growth Maximize value of transmission assets and protect our revenue stream in an RTO membership environment Continue process improvement to maintain distribution service quality while, at the same time, further enhancing financial performance Optimize generation assets through increased availability and sale of A-2
excess capacity-We also focused on:
Manage the regulatory process to Implementing an maximize retention f of earnings management sysi
..- improvement while providing fair:and Completing 'a cos reasonable rates to our customers which-we exp sustainable 'net We remain very focused on credit quality and more than $200 liquidity as discussed in greater detail. later in 2003 this report..
Eliminating or red
. -We are committed to continually evaluating' the need to reallocate resources to areas with requirements ass core assets enterprise-wide risk tem st reduction initiative ect to result in annual 'savings of million beginning in
[ucing future capital
,ociated with non-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'retum and sustainable
-principally'on supporting'our core shareholder value.
Any investment assets dispositions could affect future results of Selling our Texas etail business operations, cash'flows and possibly financial Proposing the sale of a significant condition.
condition.
portion of the Texas unregulated 2002 Overview
- -i-generation assets 2002 was a year of rapid and dramatic Otokfr20 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' Frst we wl c
demand for stability, predictable cash flows, Opprtunti t
earnings, and financial strength have replaced an m expense.
- 'their demand for rapid growth.
admitncexps.
their demand for rapid growth.
. Second, we will find opportunities to Our wholesale business did not perform well.
reduce capital expenditures.
- Third, management recommended a We had significant losses in optionstrading in-T X
4 Trdu int commondstoc the first half of the year and new investments performed well below our expectations.
dividend beginning in the second
- 0
- X quarter to a quarterly rate of $0.35 per
-We focused on financial strength by. :.
-.-. share. This will result in annual cash Isuing aPproximately $1 billion i jn '::
. 'savingsof approximately$340 million and should improve our retained
- common sockand eqity unitsearnings as well as create free cash Retiring debt of approximately $3 billion through the sale of two foreign flow to improveiquidity and pay-down retail utility companies n the U.K.
o a
debt.
Fourth, we plan to evaluate and,
- -; (SEEBoAr) and A
0
'j
- ',where.
appropriate, dispose of non-(
P*..
-- u:
- -: - :' - - -core assets:- Proceeds from these Establishing a cash liquidity reserve of '.
s w b u t r d
- .sales will be used to reduce debt.
- 1 -
b:-I illon;at year-enad V:
$1 bl at y
-end Fifth, we will continue to evaluate the See' Financing~-Activity in Management's --
potential for issuing additional equity
- -, Discussion and Analysis o f - Financial -
to further 'strengthen our balance Condition, Accountina"Plyis o ancil other: - '-: -'-
sheet and maintain credit quality.
Accountig Policies and te Matters in section'-M for an overview of all W rmi c i
t b
a low-cost changes to capital, structure.
provider of electricity, to serving our
-3
- -, I -- _i 7 -, __ -
5 f#
customers with excellence and to providing an attractive return to investors.
We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets.
Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Maffers.
We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors.
Results of Operations In 2002, AEP's principal operating business segments and their major activities were:
Wholesale:
o Generation of electricity for sale to retail and wholesale customers o
Gas pipeline and storage services o Marketing and trading of electricity, gas, coal and other commodities o
Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity trans-mission o
Domestic electricity disti-bution Other Investments o Energy Services Net Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001.
The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. In 2002, the Company's Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3).
Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP's wholesale marketing
- business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. The effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.
Our wholesale business has been affected by a slowing economy.
Wholesale-energy margins and energy use by industrial customers declined in 2002 and 2001.
Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO.
Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues in 2002 and 2001.
Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001.
A-4
Volatility in 'energy commodities markets 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-tern 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
.,-, For.-:
The Year Ended..
, :.=operations, as well as the recognition of Dor Tecebr 31ded
-revenues for generation projects completed 2002.2001 2000 for third parties.
The increase in 2002 (in iiiilions?o 7
WHOLESALE:
Wholesale Gas revenues resulted from a full Residential,
$ 3,713 $3,553$3 511 year of HPL operations compared to a partial commercial 2,156 2,328. 2,249~
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 Custom.ers-385.:
419 414
- financial trading and MTM unrealized losses.
Electricity Marketing (net) 2,227
' 802' 1,073" X
- Other nvestments revenue decreased in unrealized m0rm 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)
(3.356) (3.174)
-;and reported upon settlement, sales under wholesale Electric R.3F6 6.976-7 fnnAcrd tradina.nn 2,274 -
310'
,h.
,:-purchase,,
I Wholesale Gas 2-622 3
442 2002, we TOTAL WHOLESALE 10.988 9.297 7.834 l revenues DOMESTIC ELECTRICITY permitted DELIVERY:
Transmission 922 1,029
'1,009 Distribution 2.629 2.327 2.165 Kilowatthc TOTAL DOMESTIC decreasec ELECTRICITY 2001.
1 DELIVERY 3.551 ; 3.356 3.174 OTHER
~~~~economic' INVESTMENTS 16 114,
105 2001 Sal due to wez TOTAL REVENUES 4
J76
' econmic
- Certain revenues in 'the Wholesale business
'wholesale 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-S underforward trading contracts as I energy expenses. Effective July 1,
!reclassified such forward trading and purchases on a net basis, as by EITF 98-10'(see Note 1).
iur sales' to industrial customers I by.10% in.2002 and by 5% in
-his ' decrease was due to the slo'w;down which began in late les to residential customers rose 5%
ather related demand in 2002. The slow down reduced demand and prices especially in the latter part of Gas Marketing' (net) 3,021 Unrealized MTM Tnrnmp
Operatinq Expenses Increase Changes in the components of operating expenses were as follows:
Fuel and Purchased Energy:
Electricity Gas Maintenance and other operation Non-recoverable
.Merger Costs Asset Impairments Depreciation and Amortization Taxes other Than Income Taxes Total S2 Increase (Decrease)
From Previous Year 2002 2001 (in millions)
Amount Amount 959 404 43.7 $(1,275)(36.7) 14.7 2,339 570.5 303 8.2 228 6.5 (11) (52.4) 867 N.M.
(182) (89.7) 134 10.8 152 13.9 51 7.6 (16) (2.3) 2Z,0 25.6 S
13.3 The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001.
The return to service of the Cook Plant's two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation. The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001.
The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full year's expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001.
Maintenance and Other Operation expense rose in 2001 mainly as a result of additional traders' incentive compensation and accruals for severance costs related to corporate restructuring.
With the consummation of the merger with CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected, merger costs declined in 2001 and 2002 after the merger was consummated.
In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling
$1.4 billion (consisting of approximately, $866.6 million related to asset impairments,
$321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included:
2002 Pre-Tax Estimated LosS (in millions)
Asset Impairments Held for sale Asset Impairments Held and Used Investment value Losses
$ 483.1 651.4 291.9 Total S1,426.A Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations.
The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service.
Depreciation and Amortization expense increased in-2001 primarily as a result of the A-6
commencement of amortization of transition This inc generation regulatory assets in the Ohio, increase Virginia and West Virginia jurisdictions due to of $63 rr passage of restructuring legislation, the:new sale of a businesses acquired in 2001 and additional ExpensE investments in
- Property, Plant and in 2001 Equipment; fiber opti
- t :.-
- ..1).
Taxes Other Than Income Taxes increased in 2002 due to a full year of state excise taxes Income' which replaced the state gross receipts tax in.
Ohio and increased local franchise taxes in The dec Texas partly offset by the effect of Texas one-was due time 2001 assessments and decreased gross offset by Texas receipts taxes due to deregulation.
operatiol Interest. Preferred Stock Dividends, Minority Although Interest consider decreas The decrease in Interest in 2002 was primarily 12000 pri due to a reduction in short-term interest rates "
result of and lower outstanding balances of short-term deductio debt and the refinancing of long-term debt at merger r favorable interest rates offset in part by an increased amount of long-term debt Extraord outstanding.
The loss Interest expense decreased 15% in 2001 due related t(
to the effect of interest paid to the IRS on a from the COLI deduction disallowance in 2000 and and 3) lower average outstanding short-term debt Cumulat balances and a decrease in average short-January term interest rates.
In 2001 Minority Interest in Finance Subsidiary
'$48 milli4 increased substantially in 2002 because the excise tE distributions to minority interest were in effect The app for the entire year.
In 2001 we issued a generatii preferred member interest to finance'the Ohio, Vii acquisition of HPL and paid a preferred return which re of $13 million to the preferred member loss of $
interest. The minority interest was only in effect during the last four months of 2001.
New acc 2001 re Other Income/Other Expenses required supply Other Income increased by $110 million or derivativ 33% in 2002 due to the sale of AEP'S retail new ruk electric providers in Texas and due to non-earnings operational revenue.(see' Note 1).
Other which is Expenses increased $134 million or 72% in:
Accounti 2002 due to non-operational expenses (see Note 1).
Other Income increased $240 million in 2001.^
A-7 rease was primarily caused by: an in equity eairnings due 'to acqui.sitions tillion and'a $73 million gain from the generating plant (see Note 1). Other
~s increased by $1 1 0 million or 143%.
Jue to costs to 'exit air transportation,.
c and Datapult businesses (see Note Taxes rease in total Income Taxes in 2002 to a decrease in pre-tax book income
'the tax effects of the sale of foreign ns.
pre-tax book -income increased
'ably. in
- 2001, Income Taxes Bd due to the effect of recording in, or year federal income taxes as a
- theainsallowancfe of LI interest nsinred by te ISandnondeductible elated costs in 2000.
inary Losses and Cumulative Effect for transitional goodwill impairment i SEEBOARD and CitiPower resulted adoption of SFAS 142 (see Notes 2 and has been reported as a ive Effect of Accounting Change on 1, 2002.
Ne recorded an extraordinary loss of yn net of tax to write-off prepaid Ohio axes stranded by Ohio deregulation.
lication of regulatory accounting for n was discontinued in 2000 for the
-ginia and West Virginia jurisdictions suIted in the after-tax extraordinary 35 million.
ounting rules that became effective in garding accounting for derivatives us to mark-o-market certain fuel
-ontracts that qua lify as financial es. The.effect of initially adopting the s at July 1, 2001 wasa favorable
- effect of, $18 million, net f tax, reported as a Cumulative Effect of ng Change.:
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 96 S 88 S 99 CitiPower (123)
(6) 17 Pushan (7) 4 7
Eastex (156)
(l)
_t10) 8
$122 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 neted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not neted 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 EndedJ December31 2002 2001 2000 REVENUES':
wholesale Electricity
$ 8,366
-$6 6976
$ 7,392 wholesale Gas 222,31442 Domestic ElectriCity. Delivery 3,551 3,356: ~3,174 other Investment 114.
105 TOTAL REVENUES 14,555 hh 1.1
- EXPENSES:
.Fuel and Purchased Energy:
Electricity.
3,154' 2,195 3,470 Gas:
- I12 j749 1
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 113.585 9.L338 OPERATING INCOME 1,263 2,182 1,774 OTHER INCOME.44 335 95 LESS: INVESTMENT-VALUE AND OTHER,IMPAIRMENTz LOSSES 31 LESS: OTHER EXPENSES 321 LESS: INTEREST~
- 785,
-PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 1
MINORITY INTEREST IN FIAC USDAY35 INCOME BEFORE INCOME TAXES
.235 INCOME TAXES 214 INCOME BEFORE DISCONTINUED OPERATIONS,,EXTRAORDINARY ITEMS,
~AND CUMULATIVE EFFECT.
21 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX)
(190)
EXTRAORDINARY LOSSES (NET OFTA)
DISCONTINUANCE OF REGULATORY ACCOUNTING FOR'GENERATION LOSS ON REACQUIRED DEBT CUMULTIVEEFFECT OF ACCOUNTING,CHANGE (NET OF TAX)
A3 )
NET INCOME (LOSS)
AVERAGE NUMBER OF SHARES OUTSTANDING 33 EARNINGS (LOSS) PER SHARE:
Income Before Discontinued operations, EXtraordinary.
Items and umulative EffeCt of ACounting change,
$ 0.06 Discontinued perations (0.57)
EXtraordinary LoSses, cumulative Effect of Acounting change (1.06)
Ea'rnings (LoSs) Per share (Basic and Diluted)
AZ CASH DIVIDENDS PAID PER-SHARE
____D see NVotes to Conso7idated Financial S ta temnents beginning on page L-1.
A-9 187 844 10*
13 1, 463 546 917 86
- (48),
312
$2.85 0.26 (0.16) 0.06 3$
L A O 77 999 782
~602 122
,(35) 322
$ 0. 56 0.38 (0. 11)
AMERICAN ELECTRIC POWER COMPANY, INC.
Consolidated Balance Sheets (in millions - except share data)
ASSETS CURRENT ASSETS:
Cash and cash Equivalents Accounts Receivable:
Customers Miscellaneous
- Allowance for uncollectible Accounts Fuel, Materials and supplies Energy Trading and Derivative Contracts other AND SUBSIDIARY COMPANIES I
I December 31.
2002 2001
$ 1,213 466 1,394 (119) 1,166 1,046 935 6.10 TOTAL CURRENT ASSETS PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production Transmission Distribution Other (including gas and coal mining assets and nuclear fuel)
Construction work in Progress Total Property, Plant and Equipment Accumulated Depreciation and Amortization 17,031 5,882 9,573 3,965 1.406 37,857 16,173 NET PROPERTY, PLANT AND EQUIPMENT REGULATORY ASSETS SECURITIZED TRANSITION ASSETS INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS ASSETS HELD FOR SALE ASSETS OF DISCONTINUED OPERATIONS GOODWILL LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 21,684 224 343 1,365 (69) 1,037 2,125 639 5.664 17,054 5,764 9,309 4,272 1.015 37,414 15, 310
- 22. 104 3.162 735 283 247 396 824 633 721 3.954 392 795 OTHER ASSETS I
TOTAL ASSETS S3_
see Notes to onso7idated Financia7 statements beginning on page L-1.
A-10
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUI Consolidated Balance Sheets LIABILITIES AND SHAREHOLDERS' EQUITY
-CURRENT LIABILITIES:
- Accounts Payable Short-term Debt
'Long-term Debt Due Within one Year*.
Energy.-Trading and Derivative Contracts....,
other TOTAL CURRENT LIABILITIES LONG-TERM DEBT*.
EQUITY UNIT SENIOR.NOTES LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS DEFERRED INCOME:TAXES DEFERRED INVESTMENT TAX CREDITS DEFERRED CREDITS AND REGULATORY LIABILITIES 3SIDIARY COMPANIES December 31.
2002
- 2001
$ 2,042 3,164
.1,633 1,147 1,804 9.790 8.487 376 484 3.916 455 765 DEFERRED GAIN ON SALE AND-LEASEBACK -.ROCKPORT-PLANT UNIT:2 185 OTHER NONCURRENT LIABILITIES :-
1.903 LIABILITIES HELD FOR SALE 91 LIABILITIES OF DISCONTINUED OPERATIONS X__-_-__
COMMITMENTS AND CONTINGENCIES (Note 9) -
CERTAIN SUBSIDIARY-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH 321 SUBSIDIARIES MINORITY INTEREST IN FINANCE SUBSIDIARY 759-CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES*,
145 COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par value $6.50:
- -:X
--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 Paid-in Capital 3,413 Accumulated other comprehensive Income (Loss)
(609)
Retained Earnings 1.999 TOTAL 'COMMON SHAREHOLDERS',: EQUITY-.
7,064
'TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ;
- See Accompanying schedu7es.
See Notes.to Consolidated Financial statements'beginning on page L-1.
-0 f -9 : ~~~~-
a -I-l0f0
$ 1,914 4,011
_1,095
.- 1,877 1L924 I: i-08210 8 _10 603
---4, 500 491 819 194 1.334 87 2,582 750 156 2,153 2,906 (126) 3.296 8.229
$3.
29 7..
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES consolidated statements of cash Flows (in millions)
OPERATING ACTIVITIES:
Net Income (Loss)
PlUS:
Discontinued operations Net Income from Continuing Operations Adjustments for Noncash Items:
Asset Impairments, Investment value and other Impairments Depreciation and Amortization Deferred Investment Tax credits Deferred Income Taxes Amortization of Operating Expenses and Carrying charges cumulative Effect of Accounting change Equity Earnings of Yorkshire Electricity Group plc Extraordinary LOSS Deferred costs under Fuel clause Mechanisms Mark-to-Market of Energy Trading Contracts Miscellaneous Accrued Expenses Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net)
Fuel, Materials and supplies Accrued Revenues Accounts Payable Taxes Accrued Payment of Disputed Tax and Interest Related to COLI change in other Assets change in other Liabilities Net cash Flows From Operating Activities INVESTING ACTIVITIES:
Construction Expenditures C
Purchase of Gas Pipe Line Purchase of U.K. Generation Purchase of coal Company Purchase of Barging operations Purchase of wind Generation Proceeds from Sale of Retail Electric Providers Proceeds from Sale of Foreign Investments Proceeds from sale of U.S. Generation other Net cash Flows used For Investing Activities FINANCING ACTIVITIES:
Issuance of common stock Issuance of Minority Interest Issuance of Long-term Debt Issuance of Equity Unit Senior Notes Retirement of Cumulative Preferred Stock Retirement of Long-term Debt
(
change in short-term Debt (net)
Dividends Paid on Common stock Dividends on Minority Interest in subsidiary Net cash Flows From (used for) Financing Activities Effect of Exchange Rate changes on Cash Net Increase (Decrease) in cash and cash Equivalents cash and Cash Equivalents from Continuing operations -
Beginning of Period Cash and Cash Equivalents from Continuing operations -
End of Period
_2 Year Ended December 31.
2002 2001 2000 (519) 540 21 1,188 1,403 (31)
(66) 40 (31) 263 30 (152)
(127)
(283) 52 (216)
(177)
(237) 1.677 971 (86) 885 1,277 (29) 157 40 (18) 50 340 (257)
(384) 1,766 (78) 35 (478)
(147)
(239)
(161) 2.759 1,722)
(1,654)
-1 (727)
(943)
(101)
(266)
(175) 146 1,117 383 265 37 (42)
(422)
(3,260) 656 2,893 334 (10) 2,514)
(829)
(793)
(263)
(3) 989 224
- 1, 13 11 744 2,863 (5)
(1,570)
(790)
(773)
(5) 475 (27) 251 224 267 (122) 145 1,152 (36)
(190) 48 (44) 35 (449)
(170) 217 (1,530) 149 (71) 1,292 171 319 (283) 386 1,141 (1,468)
(18)
(1.486) 14 878 (21)
(1,303) 1,328 (805) 91 30 (224) 475
$ _251 Net Increase (Decrease) in cash and Cash Equivalents from Discontinued operations s (100)
Cash and cash Equivalents from Discontinued operations -
Beginning of Period 108 cash and Cash Equivalents from Discontinued Operations -
End of Period
$_8 See Notes to consolidated Financia7 Statements beginning on page L-1.
A-12 17 91 (17) 108 91
AMERICAN ELECTRIC POWER COMPANY, INC.AND SUBSIDIARY COMPANIES -
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income (in millions)
Acumu:a:ed
.Q.-
~~~~~~~~~~~~~~~~Accumulate Common Stock Sharp Amount DECEMBER 31, 999 33 Issuances Cash Dividends Declared other
- 'comprehensive Income:
other Comprehensive ncome1 Net of Taxes Foreign Currency Translatlon Adjustment.
Reclassification Adjustment For Loss Included -in Net Income Net Income Total comprehensive Income DECEMBER 31, 2000 Issuances Cash Dividends Declared other comprehensive Income:
.Other comprehensive Income, Net of Taxes Foreign currency Translation Adjustment unrealized Gain (Loss) on.
Hedged Derivatives Minimum Pension Liability Net Income Total Comprehensive Income,-,
DECEMBER 31, 2001
- Issuances Cash Dividends Declared other i :
-$2,149 I.
3 331
$2,152
- Paid-In Retained capnital Ea;;rni naS
$2,898 11,.
6
$2,915
- S2,915 -
9 (18) 331' S2,153
$2,906 17
. 108 568
- 1.
6 )
comprehensive Income:
other comprehensive ncome1 Net of Taxes Foreiqn Currency Translation Adjustment unrealized Gain (Loss) on Hedged Derivatives Minimum Pension Liability.
unrealized Loss on securities Available For Sale Net Income (Loss)
Total comprehensive Income
-- DECEMBER 31, 2002 34E See Notes to conso7idated. Financia7 Statements S3,630
- (805)
(2)-
' other Comprehensive Income (Loss) -Total S. (4)
$8,673 14
'. : (805) 4 I
-86 (119) 20 267
$3,090 S(103)
(773) 8 (14)
- - t.
' (3)
(6) 971
$3,296 f(126)
(793) 15
- 117 (13)
(585)
(2)
- .(519)
(119) 20 267 168
$8,054 10 (773) 7,281-(14)
-(3)
(6) 971 948
$8,229 676 (793) t46)
(163) 117 i
'(13)
(585)
(2)
(519 (1.002)
- egIn o
Lfi.;
-beginning on page L-1.--:.
A-13
- ~~~~~~~~~~_
C.-_
I I
w
- " E
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) outstanding(f) Millions)
Not subject to Mandatory Redemption:
4.00% - 5.00%
$102-$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 14-5 December 31. 2001 call Price per Shares shares Amount (In share(a)
Authorized(b) outstanding(f)
Millions)
Not Subject to Mandatory Redemption:
4.00% -
5.00%
$102-S110 1,525,903 614,608 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 52 7% (e)
(e) 250,000 100,000 10 Total subject to Mandatory Redemption (c) 95 Total Preferred Stock 156 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 $100 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.
Cc) shares outstanding and related amounts are stated net of applicable retirements through sinking funds(qenerally 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 o S'ubsidiaries
~weighted Average Maturity
~~~~~Interest Rate
- interest2tes at December 31.'.
ncme 31.
December 31. 2002 00 201 2002 2001 (imfllionsT
'FIRST MORTGAGE BONDS (a):
2002-2004.
6.87 6 00%-7..85%
6.00%-7.85%
4 1,246~
2005-2008:
.6.90%:
62%8 6.20%-8%
463
.699, 2022-2025
.7.66%
.~~~~~~6.875-8.7%,
6-7/8%-8.80%
773 85 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 Cc) 2002-2021 5.4
.732%-9.60% ~4.048%-9.6%5221 SENIOR UNSECURED NOTES, 2002-2005 5.53%'
2.12%-7.45%
2.31%-7.45%
- 1,834
.1,910; 2006-2012..
5.912%
4.31%-6.91%
6.125%-6.91%
2,295 1,727 2032-2038 6.64%
6.00%-738.
720--/%690 34 JUNIOR DEBENTURES 2025-2038
.7.90%.
7.60%-8.72%
7.60%-8.72%
205 618
.SECURITIZATION BONDS 2003-2016.
5.40%
3.4-6.25%_-
97 OTHER LONG-TERM DEBT (d)
.~247 258 Unamortized DiScouint '(net)
(32)
Total Long term.Debt Outstandi-ng 0109,505 Less Portion Due Within ne Year 1 633 1 095 Long-term Portion, EQUITY UNIT SENIOR NOTES 2007 5.75%
. 5.75%.
L7____
NOTES TO SCHEDULE OF-CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) Frst mrtgag bond ar~secured by first mortgage liens on electric property, patadeupet Cb)
For certain series of installment purchase contracts interest rates are subiject 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 C)to specified short-term interest rates.
d)other long-terMrdebt 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 autstanding at December 31, 2002 (i ncludes Equity unit senior Notes) is payable as follows:
Cmn millions) 2003 S 1,633 2004 824
~2005 993 2006 1,611, 2007 1, 081 Later Years438 10,528 wunamortized DiSCOUnt 32 Total "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.
combi ned 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
INDFPFNDFNT AlITC)RS' RFPORTd To the Shareholders and Board of Directors'
'of AmericanElectric 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 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 standardsrequire 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
/
i.
z,
I
MANAGEMENT'S 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 Company's 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, Deloifte & Touche LLP - independent auditors and the Company's 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
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES, I:'
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, INCOME STATEMENTS DATA:
operating Revenues Operating Expenses operating Income (Loss)
Nonoperating Items, Net Interest charges Net Income (Loss)
Preferred stock Dividend Requirements Earnings (Loss)
Applicable to Common Stock
$1,526,764 1.375.575 151,189 16,726 93.923 73,992 4.601 69,391 2001
$1,526,997 1.367.292 159,705 9,730 93.647 75,788 4.621 2000 (in thousands)
$1,488,209 1.522,911 (34,702) 9,933 107.263 (132,032) 4.624 1999
$1,351,666 1.243,014 108,652 4,530 80.406 32,776 4.885 71,16Z 1998
$1,405,794 1.239,787 166,007 (839) 68.540 96,628 4.824 91,804 2002 2001 BALANCE SHEETS DATA:
December 31, 2000 (in thousands)
Electric Utility Pl ant Accumulated Depreciation and Amortization Net Electric Utility Plant
$5,029,958
- 2. 568.604 Total Assets
$4,923, 721 2,436.972
$2,486,749
$4,394,062
$4,871,473 2.280. 521
$2,59,952
$ 5,774,108
$4,770,027 2.194.397
$4,575,21Q
$4,631,848 2.081.355
$4,148 523 Common stock and Paid-in capital Accumulated other Comprehensive Income (Loss)
Retained Earnings Total Common shareholder's Equity Cumulative Preferred stock:
Not Subject to Mandatory Redemption subject to Mandatory Redemption (a)
Total Cumulative Preferred stock Long-term Debt (a) obligations under Capital Leases (a) 915,144 (40,487) 143.996 Sfl1,&1853 789,800 (3,835) 74.605 789,656 3.443 860,570 789,323 166, 389
$955,.712 789,189 253.154
$1,042, 343 8,101 8,736 8,736 9,248 9,273 64,945 64.945 64,945 64,945 68,445 74,19
$1,617,06 187,96 L$16J427 Total capitalization And Liabilities
$4,587,191
$5,774,10 (a) Inc7uding portion due within one year.
G-1 2002 1999 1998
INDIANA MICHIGAN POWER' COMPANY AND SUBSIDIARIES
'Management's Discussion and Analvsis of Results of Operations.:
I&M zis 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 northem 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.
&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 iiterest 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 I&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 forthe taxable years all member companies as a basisfor 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.
Oneratina 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 Incr (Dec provides for the sale of 390 MW of AEGCo's From Previous Year Rockport Plant capacity to KPCo through (ol iml 2001 2004. The KPCo agreement extends until Amount X
Amount December31, 2009 for Rockport Unit 1 and Retajl*
X 28.2
- 4 $ (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 agreement filed with the FERC becomes
'.wholesale operative. Therefore, I&M purchases 910 MW E
3 3
(
(-)
of AEGCo's 50% share of Rockport Plant Ener9Y 7.3 2
3.4 capacity.
Sales to AEP-Affi 1 iates (40.9) (16) 44.7 21 Total N.M..3-3 Results of OperationsN.M.
= Not Meaningful
'- During 2002 Net Incomne decreased' by $2 : -: :'*Reflects the allocation of certain transmission and distribution revenues million due to-increased operations and "included in bundled retail rates to energy delivery.
G-2
The increase in Operating Revenues in 2001 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power l&M could sell to its affiliates in the AEP Power Pool.
Operating Expenses Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000.
The changes in the components of Operating Expenses were:
Fuel Wholesale Electricity Purchases AEP Affiliate Purchases Other operation Maintenance Depreciation an(
Amortization Taxes other That Income Taxes Income Taxes Total Increase (Decrease)
From Previous Year (dollars in millions) 2002 2001 Amount Amount
$(10.6)
(4) $
39.2 19 4.7 25 4.9 36 (4.5) 13.6 24.3 1
3.8
- 1 (7.8)
(15. )
(2)
(27.2) (10) 3 (147.7) (25) 19 (92.6) (42) 2 9.3 6
(12) 4.9 8
(28) 53.6 N.M.
1
) (10)
Plant nuclear units for restart with their return to service in 2000.
Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002.
The increase in Depreciation and Amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of l&M's share of deferred merger costs.
Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and personal propertytax expense from the effect of a favorable accrual adjustment of amounts recorded in December 2000 to actual expenses.
Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income.
The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income.
Nonoperating Income.
Expenses and Income Taxes NonoDeratina N.M. = Not Meaningful Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.
Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs.
The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21 %.
Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. The decrease in Other Operation and Maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP's traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP's traditional marketing area.
Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders' incentive compensation.
Nonoperating Expenses increased in 2001 due to increased trading overheads and traders' incentive compensation.
The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income.
Interest Charqes The decrease in 2001 Interest Charges reflects the recognition in 2000 of deferred G-3
interest payments to the IRS on disputed income taxes.from the disallowance of tax deductions for COLI interest for the years -
1991-1998.-
GA T
I- ',., !
0 '
I p
a X,;,
1 7 I
7
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income i
,~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
Year Ended December 31.
2002 2001 2000 (in thousands)
OPERATING REVENUES:
wholesale Electricity Energy Delivery Sales to AEP A ffiliates TOTAL OPERATING REVENUES OPERATING EXPENSES:
Fuel Purchased Power:
wholesale Electricity AEP Affiliates Other operation Maintenance Depreciation and Amortization Taxes other Than Income Taxes Income Taxes TOTAL OPERATING EXPENSES OPERATING INCOME (LOSS)
NONOPERATING INCOME NONOPERATING EXPENSES NONOPERATING INCOME TAXES INTEREST CHARGES NET INCOME (LOSS)
PREFERRED STOCK DIVIDEND REQUIREMENTS 990,905 321,721 214 138
- 1. 526 764 239,455 23,443 233,724 462,707 151,602 168,070 57,721 38,853
- 1. 375, 575 151, 189 93,739 71,029 5,984 93,923 73,992 4.601 957,548 314,410 255,039 1.526,997 250,098 18,707 238,237 449,115 127, 263 164,230 65,518 54, 124
- 1. 367, 292 159,705 97,810 83,037 5,043
- 93. 647 75,788 4,621 966,882 311,019 210 308 1,488,209 210,870 13,785 265,475 596,861 219,854 154,920 60,622 524
- 1. 522 911 (34,702) 76,499 62,377 4,189 107,263 (132,032) 4,624 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK Consolidated Statements of Comprehensive Income NET INCOME (LOSS)
OTHER COMPREHENSIVE INCOME (LOSS)
Year Ended December 31.
2002 2001 2000 (in thousands)
$ 73,992
$75,788
$(132,032)
Cash Flow Interest Rate Hedge 3,835 cash Flow Power Hedge (286)
Minimum Pension Liability (40,201)
COMPREHENSIVE INCOME (LOSS)
$ 7 See Notes to Financia7 statements beginning on page L-1.
(3,835)
$71,95-3 G-5 ic1i5£5)
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained EarninQs-:
-Year Ended December
- 2002;:
2001
-(in thousands)
Retained Earnings January1 Net Income (Loss)
Deductions:
Cash Dividends:Declared:
Common stock
-cumulative Preferred stock:
4-1/8% Series 4.56% Series.,
4.12% Series 5.90% Series 6-1/4% Series, 6.30% Series' 6-7/8% Series.
Total cash Dividends Declared',
Capital Stock Expense..
Total Deductions Z
$ 74,605 148. 597 66 52 897 1,203
- -834, 186 :-.
4,467, 134
- ,6.0.1 3,443 75,788 79,231 229 66 72 897 1,203-834
- 1.186 4,487 139 4.626 -
. 000
$ 166,389 (132,032):
34, 357.':
26,290 230 66'..
74 897:
1,203 834 1.186 30,780 134 30,914 Retaine Earning December Retained Earnings December 31 S
N see NVotes to Financia7 statements beginning on page L-1.
G-6 I
. i
- j.,
1 ':
- . S 0 7 -
- ,:I
-I.399-
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31.
2002 2001 (in thousands)
ELECTRIC UTILITY PLANT:
Production Transmission Distribution General (including nuclear fuel)
Construction work in Progress Total Electric utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT
$2,768,463 971, 599 921,835 220,137 147.924 5,029,958 2, 568,604 2,461. 354
$2,758,160 957,336 900,921 233,005 74.299 4,923,721 2,436,972 2,486,749 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870.754 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS OTHER PROPERTY AND INVESTMENTS 83.265 120.941 CURRENT ASSETS:
cash and cash Equivalents Advances to Affiliates Accounts Receivable:
Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel Materials and supplies Energy Trading and Derivative Contracts Accrued utility Revenues Prepayments and other TOTAL CURRENT ASSETS REGULATORY ASSETS DEFERRED CHARGES 3,237 191,226 67,333 122,489 30,468 (578) 32,731 95, 552 68,148 6,511 11,899 629.016 348.212 73,649 TOTAL ASSETS See Notes to Financia7 tatements beginning on page L-1.
G-7 ASSETS 834.109 82.898 127,977 16,804 46,309 60,864 31,908 25,398 (741) 28,989 91,440 108,895 2,072 6.497 418.435 408,927 34,967
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES.
3December31.
2002 2001 (in thousands)
CAPITALIZATION AND LIABILITIES
-CAPITALIZATION:
Common Stock -
No Par value:
Authorized -
2,500,000'shares Outstanding -
1,400,000 Shares Paid-in-Capital Accumulated other comprehensive Income (Loss)
Retained Earnings Total Common Shareholder's Equity cumulative Preferred stock:
Not'Subject to Mandatory Redemption subject to Mandatory Redemption Long-term Debt.
-TOTAL CAPITALIZATION OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning other
-TOTAL OTHER NONCURRENT LIABILITIES.
CURRENT LIABILITIES:
Long-term Debt Due Within One Year
-Accounts Payable -
General
- Accounts Payable -
Affiliated Companies Taxes Accrued Interest Accrued obligations under capital Leases Energy Trading and Derivative Contracts Other
$.'56,584.-
858,560 (40,487) 143,996 1,018,653' 8,101 64,945' 1.587.062 2.678,761 620,672
..138.965 759.637 30,000 125,048 93,608 71,559 21,481-8,229 48,568 92.822 491,315 TOTAL CURRENT LIABILITIES.
DEFERRED INCOME.TAXESr'.
'DEFERRED INVESTMENT TAX CREDITS DEFERRED GAIN ON SALE7AND LEASEBACK -
ROCKPORT PLANT UNIT 2 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS_
REGULATORY LIABILITIES AND DEFERRED CREDITS 356.197 97, 709 73,885 32.261 97,426 56,584
.733,216 (3,835) 74,605 860,570' 8,736 64,945 1.312.082 2.246.333 600,244 87.025 687. 269 340,000 86,766 43,956 69,761 20,691 10,840 93,413 76.486 741,913 400.531 105.449
- 77. 592 42.936 92.039-
- $4,394,06Z L,U1ivIhVL1IVINIb NU LUNIINULNLILbS tNote 9) ij TOTAL CAPITALIZATION AND LIABILITIES See Notes to Financial Statements beginning on page L-.1.
G-8 L , : 7, -,
. 1 z I I I
-~~~~~~~~~~
- .,:
s, ;1 I -
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated statements of cash Flows OPERATING ACTIVITIES:
Net Income (Loss)
Adjustments for Noncash Items:
Depreciation and Amortization Amortization (Deferral) of Incremental Nuclear Refuelinq outage Expenses (net)
Amortization of Nuclear outage Costs Deferred Income Taxes Deferred Investment Tax Credits Unrecovered Fuel and Purchased Power Costs Changes in Certain Current Assets And Liabilities:
Accounts Receivable (net)
Fuel, Materials and supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Mark-to-Market of Energy Trading and Derivatives Contracts Disputed Tax and Interest Related to COLI Regulatory Asset -
Trading Losses Regulatory Liability - Trading Gains Change in other Assets change in other Liabilities Net cash Flows From Operating Activities
. Year Ended December 2002 2001 (in thousands) 73,992 168,070 (26,577) 40,000 (16,921)
(7,740) 37, 501 (102,283)
(7,854)
(4,439) 87,934 1,798 (9,517)
(992) 2,494 (28,233) 21.001 228.234 75,788 166,360 418 40,000 (29,205)
(8,324) 37,501 64,841 (19,426)
(2,072)
(60,185) 1,345 (62,647) 8,493 34,293 (5,871)
(5.102) 236.207 0310 2000
$ (132,03 163, 39 5,73 40,00 (125,17 (7,85 37,50 (25,30 10,74 44,42 85,05 19,44 14,83 56,85 (17,91 (7,41 (68,16 37.30 131.43 INVESTING ACTIVITIES:
Construction Expenditures Buyout of Nuclear Fuel Leases Other Net cash Flows used For Investing Activities FINANCING ACTIVITIES:
Capital contributions from Parent Company Issuance of Long-term Debt Retirement of Cumulative Preferred stock Retirement of Long-term Debt change in Advances from Affiliates (net)
Change in short-term Debt (net)
Dividends Paid on Common Stock Dividends Paid on cumulative Preferred stock Net cash Flows From (used For)
Financing Activities Net Increase (Decrease) in cash and Cash Euivalents Cash and cash Equivalents January 1 Cash and cash Equivalents December 31 (167,484) 1 759 (165. 72 5) 125,000 288,732 (424)
(340,000)
(144,917)
(4.467)
(76.076)
(13,567) 16,804 3.23 supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $89,984,000,
$92,140,000 a
$82,511,000 and for income taxes was $60,523,000, $100,470,000 and $73,254,000 in 2002, 20 and 2000, respectively.
Noncash acquisitions under capital leases were $1,023,000 a
$22,218,000 in 2001 and 2000, respectively.
See Notes to Financia7 Statements beginning on page L-1.
G-9 (91,052)
(92,616) 1.074 (182. 594) 297,656 (44,922)
(299,891)
(4,487)
(51,644) 1,969 14.835 (171,07 58 (170.48 199,22 (31 (148,00 253,58 (224,26 (26,29 (3,36 50,56 11,52 3,31
$ "4,835
~.fI....
INDIANA MICHIGAN POWER compANY AND SUBSIDIARIES Consolidated Statements of Capitalization' PREFERRED STOCK:~
$100 Par alue - Athorized 2250,000 shares
$25 Par Value - Authorized 11,200,000 shares.
CallI Price -
hre 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:
4-1/8%
106.125 20 3,5 55,369 4.56%
102
-14,412~
4.12%
. 102.728
~
6,326 1,375.
11,230 subject to mandatorY Redemption-$100 ParCb):
-5.90%. Cc) 152,000 6-1/4% (c)
-192,500 6.30% Cc.-
-132,450 6-7/%
d) 172,500 LONG-TERM DEBT (see schedule of Long-term Debt):
Fi rst ortgage Bonds installment Purchase Contracts Senior Unsecured Notes other onb term Debt Ce)
Junior De entures Less.Portion Due within one Year December~ 31.
2002 2001 (i
n thousands)
$1.018.653
$ 860.570 5,537 1,441.
1L123
- 8. 101 15,200 19,250 13, 245,
--17,.250 64.945 174, 245 310, 336 747,07 223,73 161,718' (30.000 5,
539 1,
441
- 1. 756
- 8. 736 15,200 19,250 13,245 17250 64.945
- 264,141 I~ 310,2397 I;
696,144 I
219,947 1: 1 161,611 (340,000)
Long-terM Debt Eluding Portion Due within One Year
.1.
587.062
- 1.
312.082 TOTAL CAPITALIZATION, Ca) The cumulative preferred stock is.callable at.the rice indicated plus acdrued dividends Cb) sinking fund provisions require the redemption of 1g,000 shares in 2003 and 67,500 shares i 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.. i,Shares previously 'purchased may be applied to meet, the sinking fund requirement.
Cc) commencing in 2004 and continuing throuigh 2008 I&m may redeem, at $100 pershare, 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 fnd*
provisions at its option and all remaining 'outstanding shares must be redeemed not later than 2009. The series are callable beginn-ing November 1, 2003 for the 5.90% series, December 1, 2003 for-the 6-1/4% series and arch 1, 2004 for the 6.30% series at $100 plus accrued dividends.
Cd)-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.
allable at $100 per share'plus accrued dividends beginninghFebruary, 2003.
Ce) Represents a liability for SNF disposal.including interest payable to the DOE.
See Note 9.'
See Notes to FinanCial Statelnents Abeginn? ng on. page L -1.
G-10 i,
I-
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows:
December 31.
2002 2001 (in thousands)
% Rate Due 7.60 2002 -
November 1 7.70 2002 - December 15 6.10 2003 - November 1 30,000 8.50 2022 - December 15 75,000 7.35 2023 - October 1 15,000 7.20 2024 - February 1 30,000 7.50 2024 - March 1 25,000 unamortized Discount (755)
$ 50,000 40,000 30,000 75,000 15,000 30,000 25,000 (859)
S264,_1 First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
December 31.
2002 2001 (in thousands)
% Rate Due City of Lawrenceburg, Indiana:
7.00 2015 - April 1 S 25,000 5.90 2019 - November 1 52,000 cit of
- 7. 60 6.55 (b) 4.90(c)
Rockport, Indiana:
2014 - August 1 2016 -
March 1 2025 - June 1 2025 -
June 1 2025 -
June 1 40,000 50,000 50,000 50,000 S 25,000 52,000 50,000 40,000 50,000 50,000 city of Sullivan, Indiana:
5.95 2009 -
May 1 45,000 45,000 unamortized Discount (1.664)
(1.761)
(a) A variable interest rate was determined weekly.
The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001.
(b) In June 2001 an auction rate was established.
Auction rates are determined by standard procedures every 35 days.
The auction rate for 2002 ranged from 1.3% to 1.7% and averaged 1.5%.
The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%.
Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M.
A weekly rate was selected which ranged from 1.9%
to 4.9% in 2001 and averaged 3.3% during 2001.
(c) Rate is fixed until June 1, 2007 (term rate bonds).
The terms of the installment purchase contracts require l&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants.
The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date).
Senior unsecured notes outstanding were as follows:
% Rate Due (a) 2002 6-7/8 2004 6.125 2006 6.45 2008 6.375 2012 6
2032 Unamortized September 3 July 1 December 15 November 10 November 1 December 31 Discount December 31.
2002 2001 (in thousands) 150,000 300,000 50,000 100,000 150,000 (2.973)
$Z77,02
$200,000 150,000 300,000 50,000
-(3 856)
$69;14 (a)
A floating interest rate was determined quarterly.
The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.
Junior debentures outstanding were as follows:
December 31, 2002 2001 (in thousands)
% Rate Due 8.00 2026 - March 31 $ 40,000 7.60 2038 -
une 30 125,000 unamortized Discount (3.282)
Total W
$ 40,000 125,000 (3.389)
$161,1 Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of &M.
At December 31, 2002, future annual long-term debt payments are as follows:
2003 2004 2005 2006 2007 Later Years Total Principal Amount unamortized Discount Total Amount (in thousands) 30,000 150,000 300,000 50,000 1.095.736 1,625,736 (8.674) i1.17,06Z G-11 I
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES'
'Index to combined Notest to.co'nsolidated Financial st'atements.
Thenotes to I&m's' consolidated financial -statements' are; combinhed w~ith the notes -to: fi nanci al statemen'ts for AEP and i ts other subsidiar registrants.. ;Listed below are the combined-note s that aly to &.
h combined footnotes, begin on page L-1.
Combined
-Footnote.~~
-Reference significant AcCounting PoliJ.ci es Note1
- Merger,
'Note 4 NUClear,'Pliant Restart Noe5 Effects ofR ReulatonNote 7
Custmer hoic andIndstry Restructuri ng, Note8 Commitments.and-Contingencies Note9 "Guarantees Note 10 Sustained Earnings.Improvement Initiative:.
.Note 11~
AssetzImpairments and Investment Value LosseS Nt 13" Benefit lplans Note,14 BUsiness Segments Note 16
.Risk anagement,,Financial Instruments and Derivatives Note-17 income Taxes Note 18
~Supplementary Informationhoe2 Leases Note 22 Lines of credit and sale of Receivables Note 23
'Unaudited Quarterly, Fi.nancial, Information
-Note 24
~Related Party"Transactions Note 29
~G12
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.
/sl Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 G-13
'COMBINED'NOTES TO FINANCIAL STATEMENTS
- Inri t Cnmhined Non'tc tn Finanial Staemoe-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, r:U, -VVt-UO, I UL, I NU
- 2. Extraordinary Items and Cumulative Effect AEP, APCo, CSPCo, OPCo, SWEPCo, TCC, TNC
- 3. Goodwill and Other Intangible Assets
- 4. Merger,
- 5. Nuclear Plant Restart
- 6. Rate Matters
- 7. Effects of Regulation
- 8. Customer Choice and Industry Restructuring
- 9. Commitments and Contingencies
" 10. Guarantees
- 11. Sustained Earnings: Improvement Initiative.-
AEP, SWEPCo AEP, I&M, KPCo, PSO, SWEPCo, TCC, TNC AEP, I&M AEP, KPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M,' KPCo, OPCo, PSO, SWEPCo, TCC, TNC.
AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, l&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, l&M, PSO, SWEPCo, TCC, TNC
-AEP, AEGCo, APCo, CSPCo, I&M, PSO, SWEPCo, TCC, TNC KPCo, OPCo, KPCo, OPCo,
- 12. Acquisitions, Disp6sitions and Discontinued Operations
- 13. Asset Impairments and Investment Value Losses
- 14. Benefit Plans
- 15. Stock-Based Compensation
- 16. Business Segments AEP, OPCo, SWEPCo, TCC, TNC AEP, APCo, CSPCo, I&M, KPCo, OPCo, TCC, TNC AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP AEP, AEGCo, APCo, CSPCo,.I&M, KPCo, OPCo,
- 17. Risk Management, Financial and Derivatives.
Instruments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo I PSO, SWEPCo, TCC, TNC L-1 1.., .,. :
- 18. Income Taxes
- 19. Basic and Diluted Earnings Per Share
- 20. Supplementary Information
- 21. Power and Distribution Projects
- 22. Leases
- 23. Lines of Credit and Sale of Receivables
- 24. Unaudited Quarterly Financial Information
- 25. Trust Preferred Securities
- 26. Minority Interest in Finance Subsidiary
- 27. Equity Units
- 28. Jointly Owned Electric Utility Plant
- 29. Related Party Transactions
- 30. Subsequent Events (Unaudited)
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP AEP, APCo, CSPCo, I&M, OPCo AEP AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, PSO, SWEPCo, TCC AEP AEP CSPCo, PSO, SWEPCo, TCC, TNC AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP L-2
- 1. Significant Accounting Policies:
Business Operations -. AEP's C(the Compai principal business 'conducted by its elE domestic electric utility operating companies iz generation, transmission and distributior electric power. Nine of AEP's eleven domi electric utility operating companies, AF CSPCo, I&M, KPCo, OPCo, PSO, SWEF TCC,:TNC, are SEC registrants.: AEGCo domestic generating company wholly-owne
-AEP that is an SEC registrant. These compa are subject to regulation by the FERC undei Federal PowerAct and follow the Uniform Sy, of Accounts prescribed by FERC.
They subject to further regulation with regard to r
- and, other" matters by state regulE commissions.
AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent, other commodities in the.United States.
and Europe. In addition, the Company's domestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.
International 'operations in;clude 'supply of electricity and othe r non-regulated -power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale.
The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. See Note 13 for further:
discussion of changes in our communications related business and other business operations announced in 2002.
Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility'commissions.
.The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates.
The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated by the authorities of that country and are generally subject to price controls.;
Principles of Consolidation - AEP's consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially
'controlled - subsidiaries.
The consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo.and TCC include the registrant and its wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included, in Other Income for AEP and nonoperating income for the registrant subsidiaries.
Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the
- recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.
In accordance with SFAS 71, "Accounting for the Effects of Certain Types of
.:Regulation,"
regulatory.. assets (deferred expenses). and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by
- matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business' was
' discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia byAPCo in June 2000, in Texas byTCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8,. "Customer Choice and ' Industry Restructuring" for additional information.
Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management.
Actual results could differ from those estimates.
L-3 i
Property, Plant and Equipment -
Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses.
Plants are tested for impairment as required under SFAS 144. See Note 13.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization - AFUDC is a noncash, nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. The amounts of AFUDC for 2002, 2001 and 2000 were not significant.
Effective with the discontinuance of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia, West Virginia and other non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs."
The amounts of interest capitalized were not material in 2002, 2001, and 2000.
Depreciation, Depletion and Amortization -
Depreciation of property, plant and equipment is provided on a straight-line basis,,over the estimated useful lives of property, other than coal-mining property, and is calculated largely through the use of composite rates by functional class as follows:
Functional class of Property Production:
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmi ssi on Distribution other Functional Class of Property Production:
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-Conventional and Pumped Storage Transmission Distribution other Functional Class of Property Production:
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmi ssi on Distribution other Annual Composite Depreciation Rates Ranqes 2002 2.5% to 3.4%
2.6% to 4.5%
1.9% to 3.4%
1.7% to 3.0%
3.3% to 4.2%
1.8% to 9.9%
Annual Composite Depreciation Rates Ranges 2001 2.5% to 3.4%
2.5% to 4.5%
1.9% to 3.4%
1.7% to 3.1%
2.7% to 4.2%
1.8% to 15.0%
Annual Composite Depreciation Rates Ranges 2000 2.8% to 3.4%
2.3% to 4.5%
1.9% to 1.7% to 3.3% to 2.5% to 3.4%
3.1%
4.2%
7.3%
L-4
-,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:
i Nuclear.
Steam.
Hydro-AEGCo
.3-5%
APCo 3.4 2.9 CSPCo 3 2 I&M 3.4
- 4. 5
.4 KPCo 3.8 OPCo 3.4
-2.7 PSO 2.7 SWEPCo
-3.4 TCC
- 2. 5
- 2. 6 1.9 TNC' 2.8 Depreciation, depletion and amortization of coal-mining assets is: provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for, mining structures and equipment.
The. units-of-production method is used to amortize coal rights
-and mine development costs based on estimated recoverable tonnages. These costs are included in the cost of coal charged.to'fuel expense for coal used by utility operations.
Current average amortization rates are $0.32 per ton in 2002,
$3.46 per ton in 2001 and $5.07 per ton in 2000.
In 2001, an AEP subsidiary sold coal mines in Ohio.and West *Virginia.
See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in'2002.
Cash and Cash Equivalents - Cash and cash
.equivalents include temporary cash investments with original maturities of three months or less.
Inventory - Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using' a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For those domestic utilities ' whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market.
Materials and supplies inventories are carried at average cost.
Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 Transmission 2.2-2.3 1.9 1.7 2.3-2.3 2.7
-2.3 3.1 Di str'i buti oi 3.3 3.6 4.2 3.5 4.0 3.4 3.6 3.5 3.3 General
. - 2.8%
- -3.1 3.2 :
- .3.8:
2.5 2.-7
- 6.3 4.7
.4.0 I6.8 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be
-carried atfairvalue until December31, 2002, and inventory purchased from October 26 through
.December 31, 2002 was carried at the lower of cost or market.
Effective January 1, 2003, all -
natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried. at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held.in connection with, trading operations by approximately $39 million. This change will be accounted for as a cumulative effect of a change in accounting principle.
Accounts Receivable - AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for certain non-affiliated 'utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement with a group of banks and commercial paper-conduits. This transaction constitutes a sale of receivables in accordance with SFAS 140,
-allowing the receivables to be taken off of the company's balance sheet.
See Note 23 for further details. -
Foreign Currency Translation.- The financial statements of subsidiaries outside the U.S. which are included in AEP's consolidated financial statements are measured using the local currency as the functional currency and translated into U.S.
dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets and liabilities are a I..
I I v.
translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on AEP's Consolidated Statements of Cash Flows in Effect of Exchange Rate Changes on Cash.
Actual currency transaction gains and losses are recorded in income.
Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the fuel is burned.
Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71.
These deferrals generally are amortized when refunded or billed to customers in later months with the regulator's review and approval. The amount of deferred fuel costs underfuel clauses forAEP was $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "Effects of Regulation".
We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo.
Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings.
In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings. This is also true for certain of AEP's Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 6, "Rate Matters" and Note 8, "Customer Choice and Industry Restructuring" for further information about fuel recovery.
Revenue Recognition -
Regulatorv Accountin The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo),
reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made.
When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet.
We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income.
A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivenv Activities - Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.
The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts.
In general, expenses are recorded when purchased electricity is received and when expenses are incurred.
Domestic Gas Pipeline and Storage Activities -
Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided.
Transportation and L-6
storage revenues also include the accrual of
..area, the total gain or loss realized in cash for earned, but unbilled and/or 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
-0traditional, 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 Marketin.q and Tradinq Transactions -
physical forward sale and purchase contracts with In 2000, 2001 and throughout the majority of delivery points outside of AEPis traditional 2002, AEP engaged in wholesale electricity, marketing area are included in nonoperating natural gas and othercommodity 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 'atfixed and variable or liabilities as appropriate.,
prices: and the trading of financial f'energy' contracts which includes exchange futures and For'APCo, CSPCo and OPCo, depending on options and over-the-counter options and swaps.
w hether 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 RiskManagement Activities" and purchase contracts with delivery points in (EITF 98-10). Under the mark-to-market method
'"AEP's traditional marketingareaareincludedin
-'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 arerecorded net in revenues as unrealized netbasis. Physicalforwardsaleandpurchase
- 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 pre>viously 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 upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked-to-market based mainly on AEP-developed valuation models.
The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality.
Such valuation adjustments provide for a better approximation of fair value. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models.
Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with AEP-developed price models.
As explained above, the effect on AEP's Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP's regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate.
Construction Proiects for Outside Parties -
Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition.
This method recognizes revenue in proportion to costs incurred compared to total estimated costs.
Debt Instrument Hedging and Related Activities -
In order to mitigate the risks of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges.
There were no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17 "Risk Management, Financial Instruments and Derivatives" for further discussion of the accounting for risk management transactions.
Levelization of Nuclear Refueling Outage Costs -
In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at l&M's Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.
Maintenance Costs -
Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.
See below for an explanation of costs deferred in connection with an extended outage at l&M's Cook Plant.
Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and l&M.
Other Income and Other Expenses -
Other Income includes non-operational revenue including area business development and river transportation, equity earnings of non-consolidated subsidiaries, gains on dispositions of L-8
property, interest and dividends,;an allowance for amortized over the life of the regulated plant equity funds used during construction (explained -
rinvestment.-
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, butonlyas a pass-through billing to the customer to be AEP consolidatedaOthelIcome and dut' remitted to the government entity. Excise tax December 31, collections and payments related to taxes 2002 200 ljion2)00 imposedupon the customer are not presented in OTHER INCOME:
mi the income statement.
Equity Earnings'
-S104
$123.
22
-.Non-operational Revenue
.187
'123 71:
interest and o
5.
i6 2
Debt and Preferred Stock -
Gains and losses Gaincelonesal Iof e-25 '
.16" 2
Gain on Sale of from the reacquisition of debt used to finance
-FGainrontrale o
f
-'etail 73 domestic regulated electric' utility plant are Gain on ale of!Retail
'gnrlyad'mrie h
Electric Provider 129 generally deferred
'nd amortized over the Total Other Income
$A4S
- remaining term of the' reacquired debt in accordance with.their rate-making treatment. If Property Taxes and debt associated with the regulated business is Miscellaneous Expenses
$ 142 68
$.28
-:'refinanced, the reacquisition costs attributable to Non-operational:
Expenses 17179 56
_49 the portions of the. business that are subject to Fiber Optic ad i9 cost based regulatory accounting under SFAS 71 Datapulit Exit Costs 49 Provision for Los
. are generally deferred and amortized over the Airplane
_ - ta__14.--.
term of the replacement debt commensurate with Total other Expenses
.321
$ 187: -77 their recovery in rates.- Gains and losses on the reacquisition of debt for operations'not subject to Income Taxes - TheSAEP Syste follows the SFAS 71 are reported as a Loss'on Reacquired
'liability method of accounting for income taxes as Debt, an extraordinary item on the Consolidated prescribed by SFAS 109, "Accounting for-Income. '.- -
Statements of Operations of AEP and TCC. See Taxes." Under the liability method,'-deferred discussion of SFAS 145 in New Accounting income taxes are provided for. all temporary P.pronouncements section of this. note for new differences between the book'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 consistent with 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, the FASB issued SFAS
- 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo.
SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30,2001 and Note 3 for further discussion of our components of goodwill and intangible assets.
SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually.
SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total
- goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142.
In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002.
Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities.
By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers' funds and to allow those funds to earn a reasonable return. In general, limitations include:
Acceptable investments (rated investment grade or above)
Maximum percentage invested in a specific type of investment Prohibition of investment in obligations of the applicable company or its affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities.
The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives.
Securities held in trust funds fordecommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.
Comprehensive Income (Loss) - Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by L-1 0
owners and distributions to owners segment' as viewed by the chief operating.
- .Comprehensive-income (loss) hastwo decision-maker.'
See Note 16, "Business components:
net income- (loss) and other.
Segments" :for further discussion and details comprehensive income (loss). There were no..1:')
oregarding segments.
material differences betweeni 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 Comonents00 D
2002 ecembOe1r 31,'ooo 0 -
above the market value of the underlyingcommon Components
- 2002.
2001 2000gcomo Foreign Currency (in millions)
-"stock on the 'date of grant. The following table Adjustments
- 4.
$(113) ' $ (99) i llustrates1the effect on AEP's net income (loss)
UnorealizedtiLosses '
-(2)
~
00 -and earnings-(loss) per share as if AEP had
~~~On Securities (2) unrealized Gain on
'applied the fair value recognition 'provisions of Hedged Derivatives (16)'
(3)
FASB Statement No. 123, Accounting for Stock-minimum Pension Liability 595)
(10
)
Based Compensation", to stock-based employee
)
- ,20,,
)
'- '.compensation.:"
Year Ended December 31, Accumulated Other Comprehensive' Income 2002 n2001.
2000
- (Loss) forAEP registrant subsidiaries as of p
shr data)
'December 31,L2002 and.2001 is shown in'the '
Net IncomeCLoss), as following table. Registrant subsidiary balances Deductportdals
$ (519)
S 971 267 for Accumulated Other Comprehensive Income based employee
'compensati on (Loss) for the year ended DecemberT31, 2000 expense determined' was zero.--.
under fair value
'based:method for all awards, net of December 31,'
related tax effects
- (9)
(12).
(3)
Components 2002 2001 Pro forma net.income (in thousands).
(loss)
'. _S528):
S 959 S26A cash Flow Hedges:
- APCo
$(1,920) -$.(340)
Earnings (Loss) per
- CSPCo, (27
'share:
C&M
' (286)
(3-835)
B Basic -:as reported SCl.Z)
$1 Kpco 5
(7322 (1,903)
Basic -pro forma. -
51_
0 32iW 1i:I2 :
opco 78 196)
'.(42)
' 2 Diluted -'
SWEPCo (8
'~
as reported 1,5 3IL.
O83' TCC (36)
Diluted - pro forma' B
)-
liOiB2i TNC (15) minimum Pension Liability: -
0-6' Earnings Per Share (EPS) -
AEP calculates CSPCo 5(59,090) earnings' (loss) per share in accordance with I&M'-
(40,201)
SFAS No. 128, "Earnings Per Share" (see Note OPCO (72,148) 19). Basic earings (loss) per common share is P'SO (54431) '
calculated bydividing net eamings(loss) available'
.S;W:ETCCo-: -
- :.(53,635) ;, -..
:'.-.t to common shareholders by the weighted average
~TCC
"(73,124) 0 '
TNC.V-
".(30,748) number of common'shares outstanding during the
'Reporting-The AEP s'
7 'period. Diluted earnings (loss) per common share
. Segment: Reporting -
The ' AEP System--:has '. -X t is calculated by adjusting the weighted average adopted SFAS No. 131, which requires disclosure
-- outstanding ' common
'shares,:
' assuming of selected financial information by business a
0 0 -- '- ' s ' Q L-11
conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. Basic and diluted EPS are the same in 2002, 2001 and 2000.
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS.
Reclassification - Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" and Emerging Issues Task Force Topic D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.
39". Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy.
Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.
New Accounting Pronouncements SFAS 142, "Goodwill and Other Intangible Assets", was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment.
In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations.
The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections.
As a result of that testing, AEP determined that there was a net-transitional impairment loss, which is reported as a
cumulative effect of a change in accounting principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets.
SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets.
In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized.
Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased.
SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP's and SWEPCo's intangible assets.
SFAS 143, "Accounting for Asset Retirement Obligations", is effective for AEP on January 1, 2003.
SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured atfairvalue and is capitalized as part of the related asset's capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest) will be recognized each period as an operating expense in the statement of operations.
The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects l&M and TCC) and possibly other obligations. AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities.
In addition, the. regulated transmission and 121,"Accounting for Long-lived Assets and for distribution-- entities have'- asset retirernent Long-lived Assets to be Disposed Of."
AEP obligations related to the final retirement of certain adopted SEAS 144 effective January,l, 2002.
'transmission and distribution lines. There are 9-The adoption of SFAS 144 did not materially also underground storage tanks located at various affectAEP'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 rectifiee setsat 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 SEAS 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 entityfrom recording SEAS 4,'-"Reporting Gains and Losses from an expense for, estimated costs associated with Extinguishment of Debt", effective forfiscal 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 beaggregated 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 i 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-tomarket 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 energytrading 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, continuetobeaccountedforatfairvaluethrough "Accounting for the Impairment or. Disposal of:.
December3l,2002. Energycontractsthat 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-13
Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses.
Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows.
Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. Unrealized gain or loss at inception is recognized only when the fairvalue of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts.
In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities.
This statement supersedes previous accounting
- guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan.
SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value.
The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.
In November
- 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees.
This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No.
- 34.
The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002.
The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition.
See guarantee details discussed in Note 10.
In December 2002, the FASB issued SFAS No.
148, Accounting for Stock-Based Compensation-Transition and Disclosure", which amends SFAS No.
- 123, "Accounting for Stock-Based Compensation". SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Underthe fair value based method, compensation cost for stock options is measured when options are issued.
In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation.
SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options.
In November 2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation:
A Comparison of FASB L-14
Statement No. 123, Account 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 -.;.IERS,: -. 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 SEAS 123 allowing'
- 2. Extraordinary' Items and Cumulative Effect:
Companies to disclose the pro forma effects of the fair value based method rather' than requiring Extraordinaty Items - Extraordinary items were recognition of the fair value:of employee:stock recorded, for the discontinuance of regulatory options as an expense.
accounting'under SEAS 71 for the.generation
., portion of the business in the Ohi6,Virginia, West In January 2003, the FASB issued FASB Virginia, Texas and Arkansas state jurisdictions.
Interpretation No. 46, "Consolidation of Variable SeeiNote.7 "Customer.'Choice and Industry Interest Entities":(FIN 46) which changes the Restructuring"fordescriptions of the 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' Utilit Excise Tax do not have sufficient equity at risk for the,entityto, (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.
quarterended 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 'i-GRT.
Effective with the liability affixing on May 1, recognition and initial measurement provisions of :
2001,-
CSPCo and OPCo recorded an FIN 46 forall enterprises with variable interests in extraordinary loss 'under SFAS 101. Both Ohio variable interest entities created after January31, companies appealed to the Ohio Supreme Court
- 2003, shall apply the provisions of this
-thePUCO order on Ohio restructuring that the.
Interpretation to those'entities immediat6ly.- A Ohio-companies believe:failed to provide for public entity with variable interests -in variable recovery for the final year of the GRT. In April interest entities created before February 1, 2003 '
2002, the Ohio Supreme Court denied recovery of shall apply the provisions of this Interpretation no the final year of the GRT.'
'-.:: ' later than the beginning of the-first interim or annual reporting period beginning after June 15, In October 2001, TCC reacquired $101 million of 2003.
- .:'. ' ': pollution-control bonds in advance of.their maturity.:' Since these pollution control bonds If it is reasonably possible-that an enterprise will were used to'finance 'unregulated generation consolidate or.disclose information about a assets, a loss of $2 million after-tax was recorded.
variable interest entity when this Interpretation AEP. and its registrant subsidiaries had no becomes effective,' the enterprise shall disclose extraordinary items in 2002.'
the' following information in all ' financial statements initially issued after January 31, 2003, The following table shows the components of the regardless of the date on which' the variable extraordinary: items reported on AEP's interest entity was created:
Consolidated Statements of Operations:
- a. The nature, purpose, size, and activities of.
the'variable interest entity
- b. The enterprise's maximum exposure to loss as a result of its involvement with the variable interest entity L-1 5
Extraordinary Items:
Discontinuance of Regulatory AcCounting for Generation:
Ohio Jurisdiction (Net of Tax of $20 million in 2001 and
$35 Million in 2000)(a)
Virginia and West Virginia Jurisdictions (Inclusive of Tax Benefit of $8 Million)(b)
Loss on Reacquired Debt (Net of Tax of 1 Million in 2001)(c)
Extraordinary Items Year Ended December 31.
02 2001 2000 (in millions)
(48) $(44) 9
)
$5)
(a) Relates to AEP, OPCo and CSPCo.
(b) Relates to AEP and APCo.
c) Relates to AEP and TCC.
Cumulative Effect of Accounting Change - SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment.
The implementation of SFAS 142 resulted in a $350 million net transitional loss for our U.K. and Australian operations and is reported in AEP's Consolidated Statements of Operations as a cumulative effect of accounting change (see Note 3 for further details).
The FASB's Derivative Implementation Group (DIG) issued accounting guidance under SFAS 133 for certain derivative fuel supply contracts with volumetric optionality and derivative electricity capacity contracts.
This guidance, effective in the third quarter of 2001, concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when certain option-type contracts and forward contracts in electricity can qualify for the normal purchase or sale exclusion.
For AEP, the effect of initially adopting the DIG guidance at July 1, 2001 was a favorable earnings mark-to-market effect of $18 million, net of tax of $2 million.
It was reported as a cumulative effect of an accounting change on AEP's Consolidated Statements of Operations.
- 3. Goodwill and Other Intangible Assets:
As described in the Significant Accounting Policies footnote, AEP adopted the provisions of SFAS 141 effective July 1, 2001.
SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and est6blished new standards for the recognition of certain identifiable intangible
- assets, separate from goodwill.
Business combinations initiated after June 30, 2001 (see Note 12 for details) are accounted for utilizing SFAS 141.
SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 required a two-step impairment test for goodwill. The first step was to compare the carrying amount of the reporting unit's assets to the fair value of the reporting unit.
If the carrying amount exceeded the fair value then the second step was required to be completed, which involves allocating the fair value of the reporting unit to each asset and liability, with the excess being implied goodwill.
The impairment loss is the amount by which the recorded goodwill exceeds the implied goodwill.
AEP was required to complete a "transitional" impairment test for goodwill as of the beginning of the fiscal year in which the statement was adopted.
This transitional impairment test required that AEP complete step one of the goodwill impairment test within six months from the date of initial adoption, or June 30, 2002. In the first quarter 2002, AEP completed the transitional impairment test of goodwill related to domestic operations and indefinite lived intangible assets and concluded that those assets were not impaired.
In the second quarter 2002, AEP completed testing for goodwill impairment on AEP's U.K. and Australian retail electricity and supply operations.
The fair values of the U.K. and Australian retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections.
As a result of this testing, AEP determined that there was a net transitional impairment loss of $350 million, which was reported in AEP's Consolidated Statements of Operations as a Cumulative Effect of Accounting Change.
SFAS 142 also requires that intangible assets with finite useful lives be amortized over their L-1 6
respective estimated lives, to 'the estimat straight-line basis over 1 yers.
Also, in residual values. In'accordance with SFAS 142,..
- accordance with,SFAS 142, for al business
-for all business combinations initiated before July combinations with acquisition dates afterJune 30, 1, 2001, AEP amortized goodwill and intangible,:
2001, AEP, has.-'not amortized goodwill and assets with indefinite lives through December iitangible 'assets with indefinite lives. Intangible 2001, and then ceased amortization. The assets with finite lives continue to be amortized goodwill associated with those business overtheirrespective'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
alance December 31, 2002 S356 37 S3 S9 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 longersubjectto 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).
In the 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 1 3a).
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-1 7
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)
Reported Net Income (Loss)
Add back: Goodwill amortization (a)
Add back: Amortization for intangibles with indefinite lives under SFAS 142 (b)
Adjusted Net Income (Loss)
Earnings (LOss) Per Share (Basic and Dilutive)
Reported Earnings (Loss) per share Add back: Goodwill amortization (c)
Add back: Amortization for intangibles with indefinite lives under SFAS 142 (d)
Adjusted Earnings (LOss) per share Year Ended December 31.
2002 2001 2000 (in millions)
$(519) 971
$267 39 39 8
9
$1519)
S-1-1 5315 Twelve Months Ended December 31, 2002 2001 2000
$(1.57)
$3.01
$0.83 0.12 0.12 0.02 0.03
$(1.5)
$3.15
$0.
(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.
(c) 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 Accumulatedi Carrying Accumulated Life
-Amount Amortization Amount.
Amortization (in years)
(in millions (inmillions)
Dolet Hills'.
Advanced:
Royalties (SWEPCo) 10
$35
$5
$35
$2 Less: Adjustment Due to Purchase,
- Price Reallocation (SWEPCo) 6 1
Trade name and Administration of
~Contracts
'72-unpatented Technology 10 10 Totals s
$2 Amortization of-intangible' 'assets.(primarily,,;0
- 4. Merger:
SWEPCo) was $2 million for the twelve monthsV."
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 in AEP'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.
-. hIn 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-recoverable merger costs were expensed in 2002, 2001 and 2000. Such costs included transaction and transition costs not recoverable from ratepayers. Also included in the merger costs were non-recoverable changes in control payments.
Merger transaction and transition costs of $52 million recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements through December 31, 2002. The deferred merger costs are being amortized over five to eight year recovery periods, depending on the specific terms of the settlement agreements, with the amortization ($8 million, $8 million and $4 million for the years 2002, 2001 and 2000) included in depreciation and amortization expense.
The following tables show the deferred merger cost and amortization expense of the applicable subsidiary registrants:
I&M KPCo PSO SWEPCo TCC TNC I&M KPCO PSO SWEPCo TCC TNC I&M KPCo PSO SWEPCo TCC TNC Amortization Merger Cost Expense for the Deferral at Year Ended December 31. 2002 December 31, 2002 (in millions)
$8.2
$1.7 2.9 0.6 5.0 1.6 3.9 1.1 9.1 2.6 2.7 0.8 Amortization Merger cost Expense for the Deferral at Year Ended December 31. 2001 December 31. 2001 (in millions)
$ 9.1
$1.7 3.2 0.6 6.6 1.2 5.0 1.1 11.8 2.6 3.5 0.8 Amortization Merger Cost Expense for the Deferral at Year Ended December 31. 2000 December 31. 2000 (in millions)
$ 6.9
$0.7 2.5 0.3 7.9 0.5 6.1 0.5 14.4 1.3 4.2 0.4 Merger transition costs are expected to continue to be incurred for several years after the merger and will be expensed or deferred for amortization as appropriate. As hereinafter summarized, the state settlement agreements provide for, among other things, a sharing of net merger savings with certain regulated customers over periods of up to eight years through rate reductions which began in the third quarter of 2000.
Summary of key Agreements:
State/Company Texas
I&M Michigan -
I&M Kentucky -
KPCo oklahoma - Pso Arkansas - SWEPCo Louisiana -
SWEPCo provisions of Merger Rate Ratemakina Provisions
$221 million rate reduction over 6 years.
No base rate increases for 3 years post merger.
$67 million rate reduction over 8 years.
Extension of base rate freeze until January 1, 2005.
Requires additional annual deposits of
$6 million to the nuclear decommissioning trust fund for the years 2001 through 2003.
customer billing credits of approximately $14 million over 8 years.
Extension of base rate freeze until January 1, 2005.
Rate reductions of approximately $28 million over 8 years.
No base rate increases for 3 years post merger.
Rate reductions of approximately $28 million over 5 years.
No base rate increase before January 1, 2003.
Rate reductions of $6 million over 5 years.
Rate reductions to share merger savings estimated to be 18 million over 8 years. Base rate cap until June 2005.
If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected.
See Note 9, "Commitments and Contingencies" for information on a court decision concerning the merger.
- 5. Nuclear Plant Restart:
I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant is a 2,110 MW two-unit plant owned and operated by l&M under licenses granted by the NRC.
I&M shut down both units of the Cook Plant, in September 1997, L-20
due'-to questions regardin gthe operabiity 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 December3l,2003whenth'eamortization 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 energyfuel costs and all':
6.' Rate Matters:
o utage/restart costs and related issues during the, extended outage of.the Cook Plant. The MPSC Texas Fuel-AffectingAEP, SWEPCo, TCC and approved a settlement agreement for-two open, TNC Michigan power supply cost recovery reconciliation' cases that resolved all issues Prior to the 'sta'rt 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 overfive years ending December under-recovery of fuel costs, the utility would also 31, 2003, request arefundor surcharge factor to refundor.
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 freeze in base rates through December 31,.
2003 and a fixed fuel recovery charge through a
b th March 1, 2004 in the Indiana jurisdiction,.
Fe r
p
'determine
- - Areezenbaseatesadfixepowerupply,
,--Fuel., reconciliation proceedings -eermine A freeze in base rates and fixed power supply wehrfe ot nurddrn h
costs recovery factors until January 1, 2004 reconcliation eriod werreasnblind
- forheM chiar juisdctin*:-
reconciliation period were-reasonable and for,-
the Michigan
.,urisdiction
' 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 naed uecember 31.
2002 2001
. 2000 costs Incurred I
i ;
' S1 5 S297
'Amortization of Deferrals 40 40 40 Charged to O&M Expense
- 41. -
332 At December 31, 2002 'and 2001, deferred O&M costs of $40 million and $80 million, respectively, remained in Regulatory Assets to be amortized
,.,through 2003., Also pursuant to the settlement agreements, accrued fuel-related revenues of $38 million were amortized as a reduction of revenues in each' of.2002, 2001 and 2000. At December 31, 2002 and 2001, fuel-related revenues of $37 million and. $75 million,' respectively, were included in Regulatory Assets and.will be amortized through December 31,-2003 for both jurisdictions..
.i-u would be negatively impacted.
'According to Texas Restructuring Legislation, fuel cost in the Texas jurisdiction after 2001 -is no longer subject to PUCT review and reconciliation.
During 2002, TCC and'TNC filed final fuel reconciliations with'the'PUCT to reconcile their fueli,costs' through the period 'ending December 31, 2001..:The ultimate recovery of deferred fuel:
balances at December 31, 2001' will be decided as part of their 2004 true-up'proceedings. See discussion of TCC and TNC fuel reconciliations below.
In October 2001, the PUCT delayed the start of customer choice in the SPP area of Texas. All of SWEPCo's Texas service'territory and a small I
19
portion of TNC's service territory are in SPP.
SWEPCo's existing Texas fuel cost recovery procedures will continue until competition begins.
SWEPCo will continue to set fuel factors and determine final fuel costs in fuel reconciliation proceedings during the SPP delay period. The PUCT has ruled that TNC fuel factors in the SPP area will be based upon the price-to-beat fuel factors offered by the retail electric provider in the ERCOT portion of TNC's service territory. TNC transferred its SPP customers to Mutual Energy SWEPCo effective December 1, 2002. TNC filed in 2002 with the PUCT to determine the most appropriate method to reconcile fuel costs in TNC's SPP area and a decision is expected by mid 2003.
Under Texas restructuring, customer choice to select a retail electric provider began January 1, 2002. Sales to customers using 1 MW or less will be at fixed base rates during a transition period from 2002 through 2006. As discussed in Note 12 "Acquisitions, Dispositions and Discontinued Operations", AEP sold its Texas retail electric providers (REP) and their retail customers in December 2002.
The former AEP subsidiaries serving as REPs for the ERCOT area filed with the PUCT in May 2002 to increase the fuel portion of their price-to-beat rate in compliance with the Texas Restructuring Legislation and the PUCT's rules. The Texas legislation provides for the adjustment of the fuel portion of the rate up to twice annually to reflect significant changes in the market price of natural gas and purchased energy used to serve retail customers using NYMEX natural gas prices. On July 15, 2002, the PUCT required further hearings to reconsider the validity of their existing rules for fuel factor adjustments. On July 24, 2002, the Texas REPs filed a petition with the District Court seeking an injunction commanding the PUCT to proceed to a final order based on the existing rules and prohibiting the PUCT from conducting a remand proceeding. The District Court issued an order on August 9, 2002 requiring the PUCT to comply with the existing rules. On August 26, 2002, the PUCT issued an order approving a 22%
increase to the fuel portion of the price-to-beat rates effective immediately for both REPs. The PUCT order approving the 22% increase has been appealed by parties opposing the price-to-beat adjustment.. With the sale of the REPs to Centrica in December
- 2002, Centrica is responsible for these appeals. Any adverse ruling from the appeal could impact TCC and TNC by requiring refunds for the time period AEP served the retail customers prior to the sale to Centrica (January 2002 to December 2002).
TCC Fuel Reconciliation - Affecting AEP and TCC In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 1998 through December2001 will be the final fuel reconciliation. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest.
During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses. Recommendations from intervening parties are expected in April 2003 with hearings scheduled in May 2003. A final order is expected in late 2003. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition.
Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 8 "Customer Choice and Industry Restructuring".
TNC Fuel Reconciliation - Affecting AEP and TNC In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory.
At December 31, 2001, the under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest.
During the reconciliation period, TNC incurred
$293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers. TNC's SPP customers will continue to be subject to fuel reconciliations until competition begins in SPP. The under-recovery 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 substantjal 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 tradingactivities 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 PUCT's 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 (OP) filed a joint Motion forSummaryDecision 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 forthe 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 November2002. 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 TOC 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, interening parties Million, includingitrs,o reflect: 'final have ojected 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 June28, 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 schedulirg entities (QSE) schedule loads and unaffiliated Texas utilities that the PUCT resources for ERCOT market participants 0
'-exceeded itsstatutoryauthoritytosetsuch rates L-23
during that period.
TCC and TNC were not parties to the case. However, the companies' transmission sales and purchases were priced using the invalid rates. It is unclear what action the PUCT will take to respond to the courts ruling. If the PUCT changes rates retroactively, the result could have a material unfavorable impact on results of operations and cash flows for TCC and TNC.
FERC Wholesale Fuel Complaints - Affecting AEP and TNC from January 1, 1997.
In July 2002, FERC approved a revised open access transmission tariff and refunds of $1.3 million were issued to unaffiliated entities.
Under FERC rules, the new tariffs resulted in a reallocation of previously received transmission revenues among affiliates resulting in the following income statement impact:
Increase Decrease) Revenues 2001 2002 Total (in millions)
In May 2000, certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs related to 1999 unplanned outages at TNC's Oklaunion generation station.
In November
- 2001, certain TNC wholesale customers filed an additional complaint at FERC asserting that since 1997 TNC had billed wholesale customers for not only the 1999 Oklaunion outage costs, but also certain additional costs that are not permissible under the fuel adjustment clause.
In December 2001, FERC issued an order requiring TNC to refund, with interest, amounts associated with the May2000 complaintthatwere previously billed to wholesale customers. The effects of this order were recorded in 2001. In response to the November 2001 complaint, negotiations to settle the complaint and update the contracts are continuing. In March 2002, TNC recorded a provision for refund of $2.2 million before income taxes. The actual refund and final resolution of this matter could differ materially from this estimate and may have a negative impact on future results of operations, cash flows and financial condition.
FERC Transmission Rates-Affecting AEP, PSO, SWEPCo, TCC and TNC In November 2001, FERC issued an order resulting from a remand by an appeals court of a tariff compliance filing order issued in 1998 that had been appealed by certain customers. The order required PSO, SWEPCo, TCC and TNC to submit revised open access transmission tariffs and calculate and issue refunds for overcharges PSO SWEPCo TCC TNC AEP Total
$ 2.8 3.2 (6.0)
(2.6)
$ 2.5
$ 5.3 2.8 6.0 (2.8)
(8.8)
(1.2)
(3.8) 13 5t1)
Fuel and Purchased Power -
Affecting AEP, PSO, SWEPCo, TCC and TNC PSO has Under-Recovered Fuel Costs of $75.7 million at December 31, 2002, representing fuel and purchased power costs recorded but not yet collected from retail customers in Oklahoma. The first significant item causing the under-recovery is approximately $44 million in reallocation of purchased power costs for periods prior to January 1, 2002, as described below. The other significant item impacting the under-recovered fuel costs are natural gas price increases that were not expected when PSO set its quarterly factors during 2002.
The Corporation Commission of the State of Oklahoma (OCC) is currently reviewing the reasons for the large under-recovered balance.
The AEP West electric operating companies' power is dispatched real-time on an economic basis and is later allocated among the AEP West electric operating companies using the Interchange Cost Reconstruction (ICR) system based on dispatch information from internal and external sources. ICR is designed to allocate the cost of power under the terms and conditions of the AEP West Operating Agreement.
During 2002, two ICR adjustments were made.
The adjustments were related to a 2002 true-up and a reallocation of years prior to 2002.
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 0CC 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 in'significant 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 r
esult 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 Filingr-Affectig AEPand 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: ERCOTcan 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 furtheradjustments, 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 forthe'nextthree months and rates should be reduced which would adversely to begin recoveryof 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-tern Contracts - Affecting AEP and subject to 0CC 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 issuearelong-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
' andTexas.
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 recoveryof the revised fuel and purchased powe'r 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.
A. -
- - L-25 0 -:
u ;; l:,
.. :. - T.';.-... - f:
C'. ;T
,. S. ' - ' - f 't--' 0.'- - ' 9 0 ' 0 --
I I s 7
I.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery. In late 2001, the utilities filed complaints that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were entered. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. The ALJ's order is preliminary and is subject to review by the FERC. The FERC will likely rule on the ALJ's order in 2003.
Management is unable to predict the outcome of these proceedings or their impact on results of operations.
Environmental Surcharge Filing - Affecting AEP and KPCo In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff to recover the cost of emissions control equipment being installed at Big Sandy Plant.
See NOx Reductions in Note 9 "Commitments and Contingencies".
The surcharge request, as filed, would increase annual revenues by approximately $21 million and must be approved by the KPSC before its inclusion in customers' bills. If the KPSC does not approve an increase in the environmental surcharge, results of operations and cash flows would be negatively impacted.
- 7. Effects of Regulation:
SFAS 71 requires that the AEP System's regulated rates be cost-based and the recovery of regulatory assets be probable. Management has reviewed all the evidence currently available and concluded that the requirements to apply SFAS 71 continue to be met for all electric operations in
When the generation portion of the business in Arkansas, Ohio, Texas, Virginia and West Virginia no longer met the requirements to apply SFAS 71, net regulatory assets were written off for that portion of the business unless they were determined to be recoverable as a stranded cost through regulated distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In the Ohio and West Virginia jurisdictions generation-related regulatory assets that are recoverable through transition rates have been transferred to the distribution portion of the business and are being amortized as they are recovered through charges to regulated distribution customers.
These assets are classified as "transition regulatory assets". As discussed in Note 8, "Customer Choice and Industry Restructuring" the Virginia SCC ordered the generation-related regulatory assets in the Virginia jurisdiction to remain with the generation portion of the business. Generation-related regulatory assets in the Virginia jurisdiction are being amortized concurrent with their recovery through capped rates. These assets are also classified as "transition regulatory assets." The Texas jurisdiction generation-related regulatory assets that are eligible for recovery through securitization have been classified as "regulatory assets designated for or subject to securitization.'
See Note 8 "Customer Choice and Industry 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 order to 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 a,...,..
i
AEP's recognized rgulatory assets and liabilities are comprised of the following at:
December 3.
200o2
- 2001, (in millions).
Regulatory ASsets:
Amounlts Due From Customers, For Future Income Taxes
$ 791 814 Transition Regulatory Assets 743 847 RegulatorY ASsets Designated for or Subject to Securitization 336 959 Texas wholesale Clawback Ca) ~
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 3
other
~~~~
~~~~264 193 Total Regulatory Assets Regulatory Liabilities:
Deferred Investment
'Tax credits I.45 491' Texas Retail Clawback Ca 66 other.-
419
-393 Total:Regulatory Liabilities..i4-a)See."TexaS Restructuring". section of Note 8.,
The ecogize reglatry assets ad liabilities for th'eregistrant subsidiaries are of two typeS: those earning areturn and those not earning a return: Items not earning a return have their rcvyperiod end date indicated. 'Regulatory assets and liabilities are comprised of the following items:
AEGCo APCo Recovery/
Recovery/
Refund Refund 20
-.20 Peid2002 2001. 7 Period
~~(in thousand-s)
Regulatory Asets:
Amounts Due.From Customers For Future Income Taxes
.$209,884
$189,794 Note I Tr ansition -Re gulat ory ASsets Virginia
-39,670-46,981 jun. 2007 Transition - Regulatoy Assets est Virginia 119,038 127,998.,Jun. 2011 Deferred Fuel osts -
5.367'- 11,732.
Unamortized Loss on Reacquired-Debt 4,970 :$
5,207.
Note-2 9,147. 10,421 Note 2
~Deferred storm Damage
'6;
- other
.12 447 10.451 Note 3
.. Total RegulatoryAsts Regulatory Liabilities:
- Deferred Investment Tax Credits
~$52,943 $56,304-Note 4
$ 33,691$S 38,328 Note 4 WV Rate -Stabilization
-75,601 75,601. Note 5
~Amounts Due To Customers.-
For Future Income Taxes 1660 2275 Note 1-other.____
72 112 Note 3.
Total Regulaor Libl ts 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 y'ears recovery period across.all ristrants..-
Noe3: other may include items not earning a return and would have various rcvy/eudpriodS.
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.
. 11.
I :
. I .
i
csPcoI&
2002 Regulatory Assets:
Amounts Due From Customers For Future Income Taxes Transition -
Regulatory Assets Deferred Fuel Costs Unamortized Loss on Reacquired Debt cook Plant Restart Costs Incremental Nuclear Refueling Outage Expenses (Net)
DOE Decontamination and Decommissioning Assessment other Total Regulatory Assets Regulatory Liabilities:
Deferred Investment Tax Credits other Total Regulatory Liabilities
$ 26,290 204,961 5,978 Recoveri7 Refund 2001 Period 2002 (in thousands)
$ 28,361 223,830 Note 1 Dec. 2008 7,010 Note 2 20,453 3,066 S25,68
$26,26
$ 33,907
£ 33,907
$ 37,176 31
$jZ37207 Note 3 Note 4 Note 3
$163,928 37,501 14,994 40,000 29, 572 23,375 38 842
$ 97,709 65 983 Recovery/
Refund 2001 Period
$171,605 Note 1 75,002 16,255 80,000 2,995 27,784 35 286
$105,449 52,479 Dec.
Note Dec.
Note Dec.
Note 2003 2
2003 5
2008 3
Note 4 Note 3 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.
K PCO Recovery!
Refund 2002 2001 Period 2002 (in thousands)
OPCo Recovery/
Refund 2001 Period 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 23 227 9,676 Note 3 Total Regulatory Assets
$09
$9769
$6,4 "44Z Regulatory Liabilities:
Deferred Investment Tax Credits S 9,165
$10,405 Note 4
$ 18,748
$ 21,925 Note 4 Other 12,152 6.551 Note 3 1.237 1237 Note 3 Total Regulatory Liabilities
$ 211 9
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 I&M
PSO SWEPCo Recovery!
Re covery/
Refund-
'~Refund 2002
- 2001, Period 2002-2001.
Priod Regulatory ASSetsusnds Amounts Due From Customers For.Future Income Taxes
$ 19,855. $ 16,532 Note 1 Deferred Fuel osts
$76,470 5
oe1285 8,839 Note 1 unamortized L on Reacquired Debt 11,138 12,381 Note 2 1.7,031 20,045 *Note 2 other 15 012 '22.683 Note 3 12.347 15.731 Note 3 Total Reuaoy Asets 52.09 Regulatory~ Liab:ilities:
Deferred Investment:
Tax redits
$ 32,201 -
$33,992 ~Note 4
$ 44,190
$ 48,714 Note 4 Ammounts Due To Customers For Future Income Taxes 27,893 26,085 Note 1 Deferred Fuel costs
-946 Nt 11726 5,487 Note 1 other
.4 391
-22.444 'Note-3 7.094 10,i$89 Note '3 Total:RegulatoryLibiltie A
Note 1 This aount4fluctuates 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.
%,TNC Recovery!,.
Recovery/
Refund Refund 2002
-2001%.Period 2002 2001' Period (7in.
housands)
Regulatory Assets:
Amounts Due From Customers
- For Future Income Taxes
$162,247 $ 200,496 Note 1.
Regulatory Assets-Designated For or subject-Deferred Fuel osts
$680
$40,389 Note 5 Trexas wholesale lawba:ck
- .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.
11 960 'Note 3 5.000 5.461 Note 3 Total Rgltr Asets
- 4. 5
=44 Regulatory Li abiIi ti es:;
Deferred Investment Tax redits'.
$117,686 $'122,892 Note 4,
$21,510.$ 22,781 Note 4.
Deferred Fuel'Costs 6906 5252 Note 5-Texas Retail,Clawback 51,926 Note 5 14,328 Note 5 over '-Recovery of Transition hanges'-.
20,870 J an. 2016.,
Purchased Power-Conservation 9,560 Note 1' ExcesS Earnings 611 62,8521 Note 5 17,419~ 17,300: Note-4 AmimountS Due To ustomners For Future ncome Taxes
- ,12,280 13,591.
Note 1 other 6
6 Note 3 7 285'-
5.775 '.Note:3 Trotal.Regulatory,Liabilities S-5944.
Note 1: This'iamount'fluctuates from month'to monthWor 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 mnay include items not earning a return and would have various-recovery/refund.periods.
Note 4: Generally 'amortized over'the 1i fe of the related plant assets.as approved by the various state commissions.1' Note. 5:' Includable in:TCC'5 n N'
UT20 reU rceig.
elTxsRsrcuig eto of Note 8.
anTC' PCT20 treu prceig. Se"Txs esrcuig scio L-29
- 8. Customer Choice and Industry Restructuring:
Customer choice allowing retail customers to select alternative generation suppliers began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of Texas.
Customer choice in the SPP area of Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT.
AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in Arkansas, Oklahoma and West Virginia to allow retail customers to choose their electricity supplier has been delayed or repealed.
In 2001, Oklahoma delayed implementation of customer choice indefinitely.
In February 2003, the Arkansas General Assembly passed legislation that repealed customer choice legislation, which is currently awaiting signature by the Govenor of Arkansas. Before West Virginia's choice plan can be effective, tax legislation must be passed to continue consistent funding for state and local governments.
No further legislation has been introduced related to restructuring in West Virginia.
In general, state restructuring legislation provides for a transition from cost-based rate regulated bundled electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo Customer choice of electricity supplier and restructuring began on January 1, 2001, under the Ohio Act. At January 1, 2003, virtually all customers continue to receive supply service from CSPCo and OPCo with a legislatively required residential generation rate reduction of 5%. All customers continue to be served by CSPCo and OPCo for transmission and distribution services.
The Ohio Act provided for a five-year transition period to move from cost-based rates to market pricing for electric generation supply services. It granted the PUCO broad oversight responsibility for promulgation of rules for competitive retail electric generation service and approval of a transition plan'for each electric utility company, changed the taxation of electric companies and addressed certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs.
In 1999 CSPCo and OPCo filed transition plans.
After negotiations with interested parties including the PUCO staff, the PUCO approved a stipulation agreement for CSPCo's and OPCo's transition plans.
The approved plans included, among other things, recovery of generation-related regulatory assets over seven years for OPCo and over eight years for CSPCo through frozen transition rates for the first five years of the recovery period and through a wires charge for the remaining years. At December 31, 2002, the remaining amount of regulatory assets to be amortized as recovered was $375 million for OPCo and $205 million for CSPCo.
By provisions of the Ohio Act on May 1, 2001, electric distribution companies became subject to an excise tax based on KWH sold to Ohio customers.
The last tax year for which Ohio electric utilities paid the excise tax based on gross receipts was May 1, 2001 through April 30, 2002.
As required by law, the gross receipts tax is paid in advance of the tax year for which the utility exercises its privilege to conduct business.
CSPCo and OPCo treated the tax payment as a prepaid expense and amortized-it to expense during the privilege year.
The stipulation agreement also required the PUCO to consider implementation of a gross receipts tax credit rider as the parties could not reach an agreement. Following a hearing on the gross receipts tax issue, the PUCO ordered the gross receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as proposed by the companies.
On April 3, 2002, the Ohio Supreme Court rejected the companies' arguments and affirmed the PUCO's order which established the effective date of tax credit riders in rates.
This ruling had no impact on 2002 results of operations as the companies had recorded an extraordinary loss ($30 million for CSPCo and $18 million for OPCo, both amounts net of tax) in 2001.
On June 27, 2002, the Ohio Consumers' Counsel, predict the outcome of the PUCO's investigation I,ndustrial Energy Users - Ohio and American or' its impact on 'results of-operations and Municipal Power -Ohio fileid a complaint with the businesspractices,ifany.
PUCO alleging that CSPCo.and OPCo have violated the
.PUCO's orders f. regarding--
Virginia Restructuring-AffectingAEPandAPco implementation- 'of their transition plan. and violated other -anolicable law bv failina -to In Virginia, choice of electricity supplierforretail participate in an RTO.
cstomers began:on January 1, 2002'under its re'structuringlaw. 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 theirtransmission 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 strandedcost 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,7CSPCo 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.
integrationof CSPCo,OPCo and other AEP East"
- 'Virginia's restructuring law does not permit the companies into PJM. In this 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, orto 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 aw 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 oals, the f
s g
^.
functi~~~~onally separated generatin tansmission' means to gather the required information from the',
public utilities and potential courses of action that:
and distrbution organizations The Virg SCC the PUCO could take. Management is unable to determined that generation-related regulatory assets and related amortization expense should L-31 1
7 j.,
q
be assigned to APCo's generation function.
Presently, capped rates are sufficient to recover generation-related regulatory assets. Therefore, management determined that recovery of APCo's generation-related regulatory assets remains probable. APCo did not and will not collect a wires charge in 2002 or 2003, respectively. The settlement agreements and related Virginia SCC order addressed functional separation leaving decisions related to corporate separation for later consideration.
Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC In preparation for the start of competition in Texas, CPL, SWEPCo, and WTU, the integrated electric utility companies operating in Texas, were required to make PUCT filings and legal and operational changes to their business.
AEP formed new subsidiaries, Mutual Energy CPL L.P.
and Mutual Energy WTU L.P., to act as retail electric providers (REP) in Texas beginning on January 1, 2002, the effective date of customer choice in Texas.
The CPL and WTU names continued to be used by the registrant subsidiaries which owned the generation, transmission and distribution assets located in the ERCOT areas of Texas and WTU's entire operations in SPP throughout most of 2002. In December 2002, WTU transferred its SPP retail customers to Mutual Energy SWEPCO L.P. AEP sold the new subsidiaries that serve ERCOT retail customers to Centrica in December 2002, along with the Central Power and Light and West Texas Utilities brand names. CPL and WTU changed their names to AEP Texas Central Company (TCC) and AEP Texas North Company (TNC),
respectively.
On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas.
Customer choice has been delayed in other areas of Texas including the SPP area.
All of SWEPCo's Texas service territory and a small portion of TNC's service territory are located in the SPP. TCC operates entirely in the ERCOT area of Texas.
Texas restructuring legislation, among other things:
provides for the recovery of regulatory assets and other stranded costs through securitization and non-bypassable wires charges; requires reductions in NOx and sulfur dioxide emissions; provides for an earnings test for each of the years 1999 through 2001 which will reduce stranded cost recoveries or if there is no stranded cost, provides for a refund or their use to fund certain capital expenditures; requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution utility; provides for certain limits for ownership and control of generating capacity by companies and; provides for a 2004 true-up proceeding to quantify and reconcile the amount of stranded costs, final fuel balances, net regulatory
- assets, certain environmental
- costs, accumulated excess earnings, excess of price-to-beat revenues over market prices subject to certain conditions and limitations (Retail clawback), and the difference between the price of power obtained through the legislatively-mandated capacity auctions and the power costs used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and other issues.
Under the Texas Legislation, electric utilities were required to submit a plan to structurally unbundle business activities into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility. In 2000, SWEPCo, TCC and TNC filed their business separation plans with the PUCT. The PUCT approved the plans for TCC and TNC but determined that competition in the SPP areas of Texas should be delayed indefinitely and abated SWEPCo's plan.
Operations for TCC and TNC have been functionally separated consistent with the approved plans. The delivery of electricity in ERCOT continues to be the responsibility of TCC and TNC at regulated prices.
Texas Legislation provides electric utilities an opportunity to recover regulatory assets and stranded costs resulting from the unbundling of the T&D utility from the generation facilities.
Stranded costs are the difference between L-32 l
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 bythe 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 authorize'd 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 whichnetbookvalueofTCC's'generatingassets, qualified refinancing costs offset by $185 million including regulatoryassets 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 beenri 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 n..:
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 aftersecuritizationofregulatoryassets. 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.- -
- i. -.
market prices used in the ECOM model to
.-.-..t 0 '- - :
'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 market prices, instead of using the PUCT's ECOM model estimates, enabled TCC to record a
$262 million regulatory asset and related revenues which represents the quantifiable amount of stranded costs for the year 2002 related to the wholesale prices.
Prior to the decision to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited the recognition of the regulatory assets and revenues as there was no way to quantify stranded costs. As discussed above, a defined process is required in order to determine the amount of stranded costs related to generation facility for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT during December 2002 provided such a process.
When the divestiture and the 2004 true-up processing is completed, TCC will securitize stranded costs which exceed current securitized amounts. The annual costs of securitization will be recovered through a non-bypassable rate surcharge by the regulated T&D utility over the life of the securitization bonds. Any stranded costs and other true-up amounts not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to T&D utility customers.
The Texas Legislation provides for an earnings test each year 1999 through 2001 and requires PUCT approval of the annual earnings test calculation.
The PUCT issued final orders for the 1999 earnings test in February 2001 and for the 2000 earnings test in September 2001.
The 1999 excess eamings were none for SWEPCo, $24 million for TCC and $1 million for TNC. Excess earnings for 2000 were $1 million for SWEPCo,
$23 million for TCC and $17 million for TNC.
Adjustments were recorded in results of operations as the orders were received.
The PUCT issued its final order for the 2001 earnings test in December 2002. An estimate of 2001 excess earnings of $8 million for TCC, $2 million for SWEPCo and none for TNC had been recorded in 2001.
Adjustments to reflect the PUCT staffs estimate of excess earnings ($2 million for SWEPCo, $0.7 million for TNC and none for TCC) were recorded prior to September 30,2002. The PUCT's final order regarding 2001 excess earnihgs required only minor adjustments to prior estimates.
Due to TCC's and TNC's disagreement with the PUCT's final order for the 2000 excess earnings, the companies filed an appeal in district court in 2001 seeking judicial review of the PUCT's determination of excess earnings.
The district court upheld the PUCT's order and the companies appealed that decision. A ruling on the appeal is expected in 2003.
On January 28, 2003, the TCC and TNC filed an appeal in District Court seeking judicial review of the PUCT order for the 2001 excess earnings.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of stranded costs authorized by the PUCT to be securitized. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. To the extent that the final 2004 true-up proceeding determines that TCC should recover additional stranded costs, the additional amount recoverable can also be securitized. The PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through distribution rates to the extent of any over-mitigation of stranded costs represented by negative ECOM. In 2001 the PUCT issued an order requiring TCC to reduce distribution rates by approximately $54.8 million plus accrued interest over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001.
Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five year refund period. The amount to be refunded is recorded as a regulatory liability.
Management believes that TCC will have stranded costs in 2004. TCC has appealed the PUCT's refund of excess earnings to the Travis County District Court and, depending on the outcome of that appeal (and the final outcome of the rulemaking challenge discussed below), the PUCT may revise the treatment of excess 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 str6nded ' 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-beatrate 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 retumed to the distribution ruled in February2003,'thattheTexasLegislation 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 for TCC 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 by joint 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 TNCs.ERCOT retail customers, -.- X -of state and local governments. Since the WV Due to the delay of competition for SWEPCos.
Legislature has not passed the required tax law 0 SPP area of Texas, SWEPCo continues to record
' changes,'the restructuring plan has not become and reuestrecoe ofEfelo cot's t bject tod effective. AEP subsidiaries, APCo and WPCo,
- -....... rovide electric service in W V.
Texas fuel proceedings.. Final deferred fuel pod et s
i W.
balances related to ERCOT customers of'TCC '
and TNC at December 31, 2001 will be included A Joint stipulation approved by the WVPSC i
- in the 2004 true-up procd
. I l fl
. 2000 in connection with a base rate filing, allowed in th 2004trueup prceedng. I thefinalfuel for recovery of. regulatory assets includinay balances or any amount incurred but not yet generation-relate regulatory assets thrug Rn
- aeneration-related regulatory assets through the reconciled are notrecovered, they could have a f
provisions:
R.nega tive impact on results of operations.'i-floigpos negative impact on reslt of operations-
.- X.. *..-. Frozen transition rates and a wires charge of 0.5 mills per KWH.
The retention, as a regulatory liability, on the books of a net cumulative deferred ENEC over-recovery balance of $66 millio'n to be used to offset the cost of deregulation when generation is deregulated in WV.
The retention of net merger savings prior to December 31, 2004 resulting from the merger of AEP and CSW.
A 0.5 mills per KWH wires charge for departing customers provided for in the WV Restructuring Plan.
Management expects that the approved Joint Stipulation provides for the recovery of existing regulatory assets and other stranded costs.
In order for customer choice to become effective in WV, the WV Legislature needed to enact additional legislation to preserve the revenues of state and local government. In the subsequent two legislative sessions, which usually end in March each year, the West Virginia Legislature has not enacted the required legislation. Due to the lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring in the summer of 2002.
The two closed proceedings related to the respective dockets intended originally to determine whether West Virginia should deregulate the generation business, and to develop the WVPSC's Deregulation Plan and related rules to implement the Plan.
Management has reviewed these two proceedings and has concluded that at this time it is not clear that APCo meets the requirements to reapply SFAS 71.
Management will monitor developments to determine when it is appropriate to reapply SFAS 71 to APCo's generation business.
Arkansas Restructuring -
Affecting AEP and SWEPCo In 1999, Arkansas enacted legislation to restructure its electric utility industry.
In February 2003, the Arkansas General Assembly passed legislation that repealed customer choice legislation, which is currently awaiting signature by the Governor of Arkansas.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas, Ohio, Texas, Virginia and West Virginia-Affecting-AEP, APCo, CSPCo, OPCo, SWEPCo, TCC and TNC The enactment of restructuring legislation and the ability to determine transition rates, wires charges and any resultant gain or loss under restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia resulted in AEP and certain subsidiaries discontinuing regulatory accounting under SFAS 71 for the generation portion of their business in those states. Under the provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded to reflect the economic effects of regulation by matching expenses with related regulated revenues.
The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas, Virginia and West Virginia resulted in recognition of extraordinary gains or losses. The discontinuance of SFAS 71 can require the write-off of regulatory assets and liabilities related to the deregulated operations, unless their recovery is provided through cost-based regulated rates to be collected in a portion of operations which continues to be rate regulated.
Additionally, a
company must determine if any plant assets are impaired when they discontinue SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis showed that there was no accounting impairment of generation assets.
As a result of deregulation of generation, the application of SFAS 71 for the generation portion of the business in Arkansas, Ohio, Texas, Virginia and West Virginia was discontinued. Remaining generation-related regulatory assets will be amortized as they are recovered under terms of transition plans. Management believes that substantially all generation-related regulatory assets and stranded costs will be recovered under terms of the transition plans.
If future events including the 2004 true-up proceeding in Texas were to make their recovery no longer probable, the companies would write-off the portion of such regulatory assets and stranded costs deemed unrecoverable as a non-cash extraordinary charge to earnings. If any write-off of regulatory assets or stranded costs occurred, it 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 com'menced for l&M's Michigan and operation of the line., On December 31, customers on January 1, 2002. Effective with that '
2002, theU.S. Forest Service issued a final date the rates on &M's Michigan customers'.bills 1 environmental impact statement and record of for retail electric service were.unbundled to'allow 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 addition'al 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 tobe met since I&M's rates for
-flows.
generation in Michigan continue to be cost-based regua a ted.
Lo'ng-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 OtherCommitments-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 iuder certain: force majeure consolidated domestic and foreign operations are conditions.
estimated to be $4.7billion.'
The AEP System has unit contingent contracts to
'The following table shows'.the estimated supply'approximately: 250 MW of-capacity to construction 'expenditures' of the subsidiary unaffiliated entities through December 31, 2009.
registrants for 2003 - 2005:
The commitment is pursuant to a unit power agreement requiring the delivery of energy only if (in millions) the unit capacity is available.
AEGoCO
"$SOO05 70.9 Power Generation :Facility-Affecting AEP and APCo' 1,005.7 oe nrto:aiiyn CSPCo 418.9 OPCo I&M 601.5
~KPCo 148.3 OPCo 733.4 AEP has entered into agreements with Katco Fundin PSO 262.3 -:. - 0 ::
g L.P. (Katco) an unrelatedunconsolidated TCC"
'419.6~ Q -; :- ^: -: 0 :
i special purpose entity. Katco has an aggregate, 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, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease will be accounted for as an operating lease (see Note 22), therefore neither the facility nor the related obligations are reported on AEP's balance sheet. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW), which will use the energy produced by the facility and sell excess energy. AEP has agreed to purchase the excess energy from DOW for resale. The use of Katco allows AEP to limit its risk associated with the power generation facility once the construction phase has been completed.
AEP is the construction agent for Katco, and is responsible for completing construction by December 31,2003, subject to unforeseen events beyond AEP's control.
In the event the project is terminated before completion of construction, AEP has the option to either purchase the facility for 100% of project costs or terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation date of the facility and continues until November 2006.
The lease contains extension options subject to the approval of Katco, and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Katco are sufficient for Katco to make required debt payments and provide a return to the investors of Katco. At the end of each lease term, AEP may renew the lease at fair market value subject to Katco's approval, purchase the facility at its original construction cost, or sell the facility, on behalf of Katco, to an independent third party. If the facility is sold and the proceeds from the sale are insufficient to repay Katco, AEP may be required to make a payment to Katco for the difference between the proceeds from the sale and the obligations of Katco, up to 82% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to Katco during the construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360 million, and total costs for the completed facility are expected to be approximately $510 million. For the 30-year extended lease term, the lease rental is a variable rate obligation indexed to three-month LIBOR.
Consequently as market interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately $12 million represent future minimum payments during the initial term calculated using the indexed LIBOR rate (1.38% at December 31, 2002). The Power Generation Facility collateralizes the debt obligation of Katco. AEP's maximum exposure to loss as a result of its involvement with Katco is 100% during the construction phase and up to 82%
once the construction is completed.
Maximum loss is deemed to be remote due to the collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense.
AEP would eliminate operating lease expense.
The sublease to DOW would not be affected by this consolidation.
OPCo has entered into a 30-year power purchase agreement for electricity produced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032.
Under the terms of the agreement, OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated and making monthly capacity payments.
The capacity payments are fixed through December 2005 at
$1.2 million per month. For the remainder of the 30-year contract term, OPCo will pay the variable costs to generate the electricity it purchases (up to 20% of the plant's capacity).
Nuclear Plants - Affecting AEP, I&M and TCC l&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC.
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
- -'x
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 I&M and $3 million' for TCC which is substantial..By agreement l&M and TCC are assessable if the insurer's financial resources partially liable together with all other electric utility would be inadequate to pay for losses.':
companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant The current Price-Anderson Act expired in August in the U.S. In theevent nuclear losses or liabilities 2002.. Its contingent financial :obligations still are underirisured 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.'
partyfinancial protectionrequirementsfornuclear
.: -'., incidents.
Nuclear incident Liability'- Affecting AEP, l&M andTCC SNF Disposal - Affecting AEP, l&M and TCC
- The Price-Anderson Act establishes insuranceV 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.
&M has not paid the of $10 million.
As a result, I&M could be.,
govemmenttheCookPlantrelatedpre-April1983
'. 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 towads payment of the pre-April 1983 million as its shareof 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' u'nits 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-AffectingAEP, 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&M Plant expirein 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 r method. The estimated cost of decommissioning L-39
and low level radioactive waste accumulation disposal costs for Cook Plant ranges from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2002 and 2001 and $28 million in 2000.
The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the
- licenses, STP is expected to be decommissioned using the DECON method. TCC estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of
$8 million per year.
Decommissioning costs recovered from customers are deposited in external trusts. In 2002 and 2001 I&M deposited in its decommissioning trust an additional $12 million each year related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers.
Decommissioning costs including
- interest, unrealized gains and losses and expenses of the trust funds are recorded in Other Operation expense for Cook Plant.
For STP, nuclear decommissioning costs are recorded in Other Operation expense, interest income of the trusts are recorded in Nonoperating Income and interest expense of the trust funds are included in Interest Charges.
On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are included in Other Assets and a corresponding nuclear decommissioning liability is included in Other Noncurrent Liabilities. On TCC's balance sheets, the nuclear decommissioning liability of
$98 million is included in Electric Utility Plant-Accumulated Depreciation and Amortization.
The decommissioning liability for both nuclear plants combined totals $719 million and $699 million at December 31, 2002 and 2001, respectively.
Federal EPA Complaint and Notice of Violation -
Affecting AEP, APCo, CSPCo, I&M, and OPCo Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged that AEP System companies and eleven unaffiliated utilities modified certain units at coal fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Courtforthe Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case.
The alleged modification of the generating units occurred over a 20 year period.
Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may-be required to install additional pollution control technology.
This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.
The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997).
In 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.
Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its L-40
defense.';
0 0
-;0 0> --'
- 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 contingefit 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 issuesyet August 2001the 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 controlequipmentthatmaybe requiredaswellas 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, byCSPCo). 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.
requiremerts. This includes selective catalytic reduction (SCR) technolocy on certain'units and NOxReductions-AffectingAEP,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.-
In 2000 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 reviewthe Section 126 Rule.
a range'of possible outcomes.
Our current 0 0:
-. --;:v-L41 -- :: - 0 0
.D:.
-, E:
i-.
f., - : f.. '
- t..': --. f :-. a::;.
i
='
f 0
.;.-:.-. :' :S. :..'- -
estimates indicate that compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of
$1.3 billion to $2 billion of which $843 million has been spent through December 31, 2002 for the AEP System. The range of cost estimate reflects the uncertainty over the need for certain SCR projects. Estimated compliance cost ranges and amounts spent by registrant subsidiaries at December 31, 2002, are as follows:
AEGCo APCo CSPCo I&M KPCo OPCo SWEPCo TCC Estimated Amount compliance costs Spent (in millions)
$30 -
198 1
445 234 93 45 42 -
210 5
163 135 535 -
864 387 40 24 5
5 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions.
Unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on results of operations, cash flows and possibly financial condition.
Merger Litigation -Affecting AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the courttold the SEC to revisit its conclusion that the merger met PUHCA requirements that utilities be "physically interconnected" and confined to a "single area or region."
In its June 2000 approval of the merger, the SEC agreed with AEP that the companies' systems are integrated because they have transmission access rights to a single high-voltage line through Missouri and also met the PUCHA's single region requirement because it is now technically possible to centrally control the output of power plants across many states. In its ruling, the appeals court said that the SEC failed to support and explain its conclusions that the integration and single region requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.
Enron Bankruptcy -
Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. Atthe date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron.
In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron.
Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron.
This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage reservoir and the related compression, treating and delivery systems. We have engaged in preliminary discussions with Enron concerning the possible purchase of the residual interest held by Enron in the Bammel storage facility and the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of its interest in the Bammel storage facility. We are unable to predict whether these discussions will lead to an agreement on these subjects.
If these discussions do not lead to an agreement, there may be a dispute with Enron concerning our ability to continue utilization of the Bammel storage facility under the existing agreement.
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.
useapproximately65billioncubicfeetofcushion
/
gas (or pad gas) required for the normal operation Enron has recently instituted proceedings against
'of the Bammel ga's' 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 intoafinancing arrange'mentin 1997 with Enron entities. -We believe thatwe havethe 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 fro rn.Iiabilities 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 ofa 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 predicttheoutcomeofthislawsuitorits 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. In 2002 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 attorneyfees and costs. The cases are presently (in millions).
pending a decision by the Court on competing
'.motions by; certain plaintiffs and groups of
-APCo W.
$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 will file an amended complaint. AEP intends to KPCO 1
0.7 vigorously defend against these actions. Also in
- l. OPCo -
- ;3.-6 :
- 23 1- -0 the fourth quarter of 2002, two shareholder
- The additional 2002 e n
di not mea derivative actions were filed in state court in
~The additional 2002 expense did not materially,--.
oubs Oi'gis:EP'.and its Board of Columbus, Ohio :against AEPadisBado change the cumulative expense per registrant Directors alleging a breach of fiduciary duty for subsidiary. The amounts expensed were based failure to establish and m'aintain adequate internal' on an analysis of contracts where AEP and Enron, controls over AEPs gas trading operations; and, entities are counterparties, the offsetting of-lawsuit was 'filed against AEP, certain AEP
'=receivables 'and payables,-,the aapplication of: 'executives and AEP's ERISA Plan Administrator deposits from.Enron entities and management's L-43
in federal District Court for the Southern District of New York (subsequently transferred to federal District Court in Columbus, Ohio) alleging violations of the Employee Retirement Income Security Act in the selection of AEP stock as a investment alternative and in the allocation of assets to AEP stock. These cases are in the initial pleading stage. AEP intends to vigorously defend against these actions.
California Lawsuit - Affecting AEP In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a lawsuit in Los Angeles County, Califomia Superior Court against forty energy companies including AEP and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. This case is in the initial pleading stage. AEP intends to vigorouslydefend against this action.
Arbitration of Williams Claim - Affecting AEP In October 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries by AEP.
Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that AEP owes approximately $130 million in connection with the termination and liquidation of all trading deals. AEP believes it has valid claims arising from Williams' actions and is seeking, in part, a determination that either no amount is due or that a lesser amount is due from AEP to Williams (which is fully reserved by AEP) and the extent of any other damages and legal or equitable relief available. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition.
Energy Market Investigations - Affecting AEP In February 2002, the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron, manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward.
In April 2002 AEP furnished certain information to the FERC in response to their related data request.
Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange.
The May 8, 2002 FERC data request required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative.
Senior management complied with the order and denied our involvement with those trading practices.
On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants 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 bctober: 2002, AEP dismissed, several involving power or gas in the relevant market. We' employees involved in natural gas marketing and further informed the FERO that certain' of our trading'after the Company determined that they
'0 -:
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 exdhange were throu'gh 'AEP's chief risk officer's 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 m'eet 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 attorney.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 informationwith 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 involvingsequential 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 Proposed Security 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 ali 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 theirpotential 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 owners.
For the AEP System this includes:
power generation plants, transmission systems, distribution systems and related areas of business. FERC is considering new proposals to modify the scope and timetable for compliance with the standards. Unless FERC changes the scope and timing of the original proposed standards, those standards could result in significant expenditures and operational changes in a compressed time frame, and may adversely affect results of operations and cash flows if such costs are not recovered from customers.
FERC Market Power Mitigation - Affecting AEP System A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows.
Other-AEP and its subsidiaries are involved in a number of other legal proceedings and claims.
While management is unable to predict the ultimate outcome of these matters, it is not expected that their resolution will have a material adverse effect on results of operations, cash flows or financial condition.
- 10. Guarantees:
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to recognize a liability related to issuing a guarantee, as well as additional disclosures of guarantees.
This new guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The initial recognition and initial measurement provisions of FIN 45 is effective on a prospective basis to guarantees issued or modified after December 31, 2002.
The disclosure requirements of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002.
There are no liabilities recorded for all of the guarantees described below in accordance with FIN 45 as these guarantees were entered into prior to December 31, 2002. There is no collateral held in relation to these guarantees and there is no recourse to third parties in the event these guarantees are drawn.
Certain AEP subsidiaries have entered into standby letters of credit (LOC) with third parties.
These LOCs cover gas and electricity trading contracts, construction contracts, insurance
- programs, security
- deposits, debt service reserves, drilling funds and credit enhancements for issued bonds. All of these LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary course of business. TCC issued one of the LOCs for credit enhancement of issued bonds. The maximum future payments of all the LOCs are approximately $166 million with maturities ranging from January 2003 to December 2007.
TCC's LOC was for $40.9 million with a maturity date of November 2003.
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.
The following AEP subsidiaries have entered into guarantees of third parties obligations:
CSW Energy and CSW International have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $3.7 million, which expires June 2020.
Additionally, CSW guaranteed 50%
of the.
0 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 50O.
in the event that Polk Power does not 23, 2002).- At the time of sale these guarantees make*ther debt payent SW has a were not revoked.
The total fUture maxim um maximumn future payment exposur of pyeteosefrbthcmaiss 0approximately $4.7 milion, which.expires July approximately $0.6 mhillion.
In January 2003
- 20.
these guarantees matured; and no payments under the guarantees were required.
In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power See Note 26 "Minority Interest in Finance
- lant, 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 maximu-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. In addition, 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 theworkis-.
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 is estimated 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
-:t0'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 February 2003, the guarantee
'.-:D'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 (in millions)
APCo CSPCo l&M KPCo OPCo PSO SWEPCo TCC TNC Other AEP non-registrant Subsidiaries Total
$0.7 0.8 2.0 0.7 3.3 3.4 6.7 2.5 29.9
$50.0
- 11. Sustained Earnings Improvement Initiative:
In response to difficult conditions in AEP's business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term eamings growth.
Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this amount, AEP paid $9.5 million to these terminated employees in the fourth quarter of 2002. The termination benefits expense was classified as Maintenance and Other Operation expense on AEP's Consolidated Statements of Operations and as Other Operation expense on the other registrant's statements of operations.
We determined that the termination of the employees under our SEI initiative did not constitute a curtailment under the provisions of SFAS No. 88 "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits".
AEGCO APCO CSPCo I&M KPCO oPco PSO SWEPCo TCC TNC other AEP subsidiar
-ies Totals Total Number of Terminated EmPlovees 93 19 146 16 33 17 8
37 20 731 Q.=
Tota Total Terminat Expense Benefit Reco'rded Accrued in 2002 12/31/0; (in (in milqionsTj millions
$ 0.3 S 0.3 13.1 12.2 5.0 4.5 15.0 13.1 2.6 2.5 7.5 7.1 3.1 3.0 3.3 3.1 6.0 5.5 2.0 1.6 17.5 13.0 S LiA
$65.9 Approximately $48 million of severance expense associated with 701 AEP Service Corporation employees (included in the 731 figure above) was allocated among all AEP subsidiaries. AEGCo has no employees but receives allocated expenses.
In addition, certain buildings and corporate aircraft are being sold in an effort to reduce ongoing operating expenses.
- 12.
Acquisitions, Dispositions Discontinued Operations:
and Acquisitions SFAS 141 "Business Combinations" applies to all business combinations initiated and consummated after June 30, 2001.
The following table shows the staff reductions, termination benefits expense and the remaining termination benefits expense accrual as of December 31, 2002:
2002 Acquisition of Nordic Trading In January 2002 AEP acquired for $2.2 millior and other assumed liabilities the tradin(
operations, including key staff, of Enron's Norwa and Sweden-based energy trading businesse (Nordic Trading). Results of operations ar included in AEP's Consolidated Statements Operations from the date of acquisition.
Th L-48
excess of cost over fair value of the net assets acquired was approximately $4.0 million which was recorded as Goodwill. Subsequently in the fourth quarter of 2002, a decision was made to exit the non-core trading business in Europe and to close orsell Nordic Trading as discussed under the "Discontinued Operations" section of this note.
Acquisition of USTI In January 2002, AEP acquired 1 00% of the stock of United Sciences Testing, lnc'. (USTI) for $12.5 million.
USTI provides equipment and services related to automated:: emission monitoring of combustion gases toboth AEP affiliates and extemal customers;.' Results of operations are included in AEP's Consolidated'Statements of
.Operations from the date of acquisition.
2001 On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe' Line Company and Lodisco'LLC for $727 million from Enron. The acquired assets include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a gas storage facility:and certain gas; marketing contracts.: The purchase method of accounting was used to record the acquisition.
According, to: APB Opinion No. 16 "Business Combinations" AEP recorded the assets acquired and liabilities assumed at:their estimated fair values determined by independent appraisal or by Company's management based on information currently available and on current assumptions as
': to future operations.- Based on a final purchase price allocation the excess of cost over fair value of the net'assets acquired was approximately,
$153 million and is recorded as Goodwill. SFAS 142 "Goodwill and Other Intangible Assets" treats goodwill as a non-amortized, non-wasting asset' effective January 1, 2002.' Therefore, Goodwill::'
was amortized for only seven months in 2001 on a straight-line basis over 30 years. The purchase method results in" the assets, liabilities and earnings of the acquired: operations being:
included in AEP's consolidated financial statements from the purchase date.
=:
- AEP also purchased the'following assets or acquired the following businesses from July 1, 2001 through December 31, 2001 for -an aggregate total of $1,651 million::
SWEPCo, an AEP subsidiary, purchased the. Dolet' Hills mining operations and assumed the existing' mine redlamation liabilities' at its jointly owned lignite reserves in Louisiana.
Quaker'Coal Company as part of a bankruptcy proceeding settlement. AEP also assumed additional liabilities of approximately$58 million. The acquisition includes property, coal reserves, mining operations and royalty interests in
-Colorado, Kentucky, Ohio, Pennsylvania and West Virginia.
AEP continues to operate the mines and facilities which employ :over 800 individuals. See Note 13b "Asset Im'pairm'ents and Investment
'Value Losses".
0 MEMCO Barge Line added 1,200 hopper barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450 employees
-operate the barge line. MEMCO added major barging operations on the Mississippi and Ohio rivers to AEP's barging operations on the Ohio and
..Kanawha rivers.-
-U.K. Generation added 4,000 megawatts of coal-fired generation from' Fiddler's Ferry,'a four-unit, 2,000-megawatt station on the River Mersey in northwest England, approximately 200 miles from London and Ferrybridge, a four-unit, 2,000-megawatt station :on the River Aire in northeast
-England, approximately 200 miles from London and related coal stocks.
See Note 13b "Asset Impairments and
.:-'Investment Value Losses".
-f 0 A 20% equity interest in Caiua, a Brazilian electric operating company which is a subsidiary of Vale. See Note 21,'Power and Distribution Projects". AEP converted a total of $66 million on'an existing loan
-and 'accrued interest on that loan into Caiua equity.-
See Note 13b "Asset Impairments and
- Investment Value Losses".
- Indian.Mesa Wind Project consisting of.
160 megawatts of wind generation located near Fort Stockton, Texas.
- .'0:IAcquired existing contracts and hired key staff from Enron's London-based internabtional coal trading group.
Regarding the 2002 and 2001 acquisitions, SEEBOARD's' assets and management has recorded the assets acquired discontinued operations,were:
and liabilities assumed at their estimated fair,
.values in accordance with APB Opinion No. 16 and SFAS 141 as appropriate based on currently.
available information and on current assumptions as to future operations.
Assets:-
-Plant,Property.
Dispositions..
.:,and Equipment,
'Net Goodwill 2002 other Assets Total;Assets of' Discontinued, In 2002, AEP completed a number of disposals of' operations q-qf atsdtermine.obnn-ore:'2:
t n..n.- ':'-nn-:
-liabilities, of December 31,
- 2001 (in millions)
$ 324 1,283 1,129 96
- ll
'-, 0-- -
Liabilities:
Current Liabilities
- 752' Disposal of.SEEBOARD Long-term Debt,
701 On June 18, 2002, AEP, through a wholly owned Deferred Income 268 subsidiary, entered into an agreement, subject to other Liabilities 77i European Union (EU) approval, to sell its
'Total Liabilities consolidated -subsidiary SEEBOARD, a U.K.
of Discontinued electricity supply:and distribution company. EU p
-$1:
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
-CitiPower's 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 majo'r classes of' CitiPower's assets and liabilitie's of discontinued operations are:
Revenues:
.., - -.., -,;.r
.'I 2 thV d
.,December 31,.
12 months ended 2001
- 12/31/02 (in millons) 12months ended Assets:.
.12/31/01 Current Assets.-_
$ 138 1 mt ended
- Plant, Property and12 months nded Equipment, Net-495 12/31/00
Goodwill/Intangibles
'466 other Assets 23 PretaxProfit(Loss)
.Total Assets ot Discontinued Operati ons Li abi 1 i ties:
Current Liabilities
$83 Long-term Debt
-612 Deferred Income' Taxes 55
+oor,
- oh;1;+ine
- 2A 12 months ended 12/31/02 12 months ended.
12/31/01
-12 months ended 12/31/00 CitiPower
.(in millions)
$ 204 350 338 I$ (190)
- (4) 20 Total Liabil Discontinue Operations Total' revenues anc discontinued opera CitiPower were:
- ~(i Revenues:
12 months ended 12/31/02 12 months ended
.12/31/01 12 months ended 12/31/00 Pretax Profit:
12 months ended 12/31/02 12 months ended 12/31/01 12 months ended 12/31/00 ities of
, I Disposition of Texas REPs In April 2002, AEP reached
- a. definitive agreement, subject to regulatory approval,to sell two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other I pretax profit (loss) of the consumerservices. PUCT regulatoryapprovalfor tions 'of SEEBOARD and, the sale was obtained in December 2002. On December 23, 2002 AEP sold to Centrica, the general partner interests and the limited partner EEBOARD interests in Mutual Energy CPL L.P. and Mutual in millions)
Energy WTU L.P. for a base purchase price paid in cash at closing "and certain additional payments, including a
net working :capital payment. Centrica paid a base purchase price of
$ 694
. $145.5 million which was based on a fair market value per customer: established by an 1,451 independent appraiser and an agreed customer count. AEP recorded a net gain totaling $83.7 1,596 million in Other Income: AEP (through TCC and
'TNC) will provide Centrica with a power supply contract. for-the two REPs and. back-office
--services related to these customers for a two-year period.
In addition, AEP retained the right to
$ 180 share in earnings from the two REPs above a threshold amount through 2006 in the event the 104 ^ \\
f Texas retail market develops increased earnings 91:
opportunities. Under the Texas Legislation, REPs
-are subject to a clawback liability, if.customer change does not attain thresholds required by the 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'sei the Company's 500A interest in from Centrica associated with the' back-offMce 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 aftertax) 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 Comprehensivelncome. Inthesecondquarterof 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 InJuly 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, anAEP 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
- 6. i
- r I
? i.
i i
I I t
I I,, i I
- 1
Discontinued Op'erations 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 CitiPoweri-Pushan, Estex Total (nmillions) 2002 Revee
$69
$20$5$
73
$1,028 2001 ReVenue
-1,451'
~
350 57-1,858 2000 Revenue 1563857 1,991
.2002 Earnings (Loss) After Tax 96 (J123)
(7)
(156)
(190) 2001 Earnings (Loss) After Tax, 88
()4
-8 2000 Earnings (Loss) After Tax 99, 17 7
(1)122
- 13. Asset Impairments and Investment Value Losses:,
In 2002 AEP recorded pre-a mpiments of asst (nldggowi)and in'vestments 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, other factors. These impairmnents exclude the transitional impairment loss from adoption of SFAS 142 (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
.. I I o
- a. Assets Held for Sale In 2002, AEP (and its registrant subsidiaries, as applicable) recorded the following estimated disposal of assets (including Goodwill) held for sale:
2 Assets E
Held for Sale Eastex Pushan Power Total Impairment Losses Included in Discontinued Operations Telecommunication -
AEPC/C3 Newgulf Facility Nordic Trading Excess Equipment Excess Real Estate Total Included in Asset Impairment Losses Telecommunications
-AFN Water Heater Program Gas Power Systems Total Included in Investment Value and Other Impairment Losses 002 Pre-Tax stimated Loss on Disposal (in millions)
$218.7 20.0 Business Reqistrant Wholesale AEP Other AEP
$238.7 Other
--'- Wholesale
$158.5 11.8 5.3
-- 23.9 15.7
$215.2
$ 13.8 3.2 12.2 Wholesale Wholesale, Wholesale Other Wholesale Wholesale AEP AEP AEP I AEP' AEP AEP AEP, APCo, CSPCo, I&M, KPCo and OPCo AEP
$ 29.2 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 lbss on
- I
- 1
.: j
Results of operations of Eastex have bben'reclass'ified a'sDiscontinue Oeratons in accordance with SEAS 144 as'shown' in Note 12. The asse ts and liabilities'of Eastexhv beninlddoAEs Consolidated Balance Sheets asheld for sale.-The major classes of assets6nd liabilities held f6r'sale are:
2002
- 20011, (n millions)
Assets:
Current Assets"'
$5:
Property,qp e
Plant and Equipment, e
217:':
Other Assets
-3 Total Assets Held for Sale
$15
$220 Liabilities:
Current Liabilities
$8~
5, Other Liabilities 41 Total Liabilities Held for Sale
$12 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 bf Pushan have ben recase as Discontinue Oeainsin accordance with SEAS 144.a's-discussed in Note 12. The assets and liabilities of Pushan have been classified n AEP's Consolidated Balance She'ets as held forsale.: The major classes of assets and liabilities held for sale are:
2002 2001 (in millions)
Assets:
Current Assets$19
$7 Property, Plant and Equipmet, Ne 132 16 Total Assets Held for Sale.
$151
$178 Liabilities:
Current Liabilities 8$27 Ln-term Debt 2530' Other Liabilities' 26 24 Total Liabilities Held for Sale
$29
$ 81 Telecommunications AEP ha develped bsinesss to rovide. telecommunication services to~ businesses and to other telecommunication companies through broadband fiber optic networks operat'ed 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), ajoint venture. Due to the difficult economic conditions in these businesse's 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 is expected to be completed by the 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.
Newgulfs 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 equipment available for sale. 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 In the 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.
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 i n 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 I&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 is included in Investment Value and Other Impairnent 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 fr 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
$39
$50
- 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 January2003.
- 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:
As sets 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 -ALLr-Held and Used---
Losses
$651.4 UK. 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
0
\\ 1R 0
0 f t l 0 iS; \\
o hAs a r 5su era x
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 December 2002 probability-weighted discounted cash flow analysis of the fair value of ourU.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 in Asset Impairments on AEP's Consolidated Statements of Operations.,
AEP Coal In October 2001, 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 a 2002 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 "reliability 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 RegulatoryAssets during the third quarter 2002 in AEP's Consolidated Balance Sheets (in Regulatory Assets 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 electricity from those plants is not required to meet market needs. ERCOT and AEP negotiated interim contracts for the 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 prop-sing to sell all of ifs 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 facilitywas no.
..onger.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 investrrients accounted for under APB 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 Seciment
'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 lnvestment 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.
Grupo Rede is in the process of restructuring some of its debts, and as a condition for participating in the restructuring, during November 2002 a creditor of Grupo Rede requested that AEP 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 December 2002 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 fair value 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 other than 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 L
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.
-e.
The following tables provide a reconciliation of the change's in the plans' benefit obligations and fair value of assets over the two-year period ending Dec ember 31, 2002, and a statement of the funded status as of Dece mber 31 fo rboth years:
U.S.
~
~
u Pension Plans
~
OPEB' Plans 2002 2001 2002 2001 Cm m~~~~~~~~~~~~~~~~~~~~~~illions Reconciliation-of Benefit obligation:.
obligation.at january I
$3,292.:
$316 1,645
.$1,668 Service Cost*
72 63430 Interest ost-241 232 14
.114.
Participant Contributions 3
3 8
Plan Amendments (2) 7(a ACtuarial Gain) LOSS
- 258 121 12 192 Divestitures
-(287)
(b)
Benefit Payments (278)
.(291)1 (81)
C88) curtailments
- obligation at December 31 Reconciliation of Fair value of Plan Asets:
Fair alue of Plan ASsets at January 1 S3,438~ $3,911 711
$,-704 ACtual Return on'Plan ASsets (371)
(182)
)
(31) company ontributions
.6 137 118 Participant ontributions
.1.8 Benefit Payments
.(278) 2i (81)
(88)
Fair alue of Plan As'sets at December 3 72V-t 711
- iunueu btatu5:
Funded Status at-December 31
$(788)
$ 146 S115)
$ 94 unrecognized Net Transition 93 (ASset) obligation Cot (7),
(15)
.233 263 Unrecognized Prior-Service Cot (13)
(12) 67-Unrecognized Atuarial (Gain LS 1.020 3'896 649 Prepaid Benefit (Accrued Li ability)
S22 15S4
$L)
(a) Related to the purchase of Houston Pipe Line comparny 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 nco'me for 2001 and 2002 were recorded in 2002.
Prepaid Benefit osts ACcrued Benefit Liabilit Additional iniMum Liabi intangible Aset ACcumulated other comprehensive Income' Net Asset.(Liability) other omprehensiv e (Inc Expense Attributable tc change in Additional Pe LiabilitY Recognition N/A = Not Applicable U. S.
U. S.
Pension Pl ans OPEB Plans 2002 2001 2002 2001 (Zin millions)
S$255
$ 205.
y
~(44)
M(51) (19)
(16:
ity (944)
.(15)
N/A N/A 45 9
N/A N/A 6
N L
/
ome).
!nsi on:
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 bernefits 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 peryear by 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.
- 0.
u.s;.
-:- -: 2002.
Service Cost S
72 Interest Cost, 241 Expected Return on Plan Assets (337)
Amortization of Transition (Asset) obligation (9)
Amortization of Prior-service Cost (1)
Amortization of Net Actuarial
.(Gain) Loss (10)
Net Periodic Benefit Cost (credit)
(44)
Curtailment Loss (a).
Net Periodic Benefit Cost (credit) After curtailments 54A)
Pension Plar V.2001, '
S 69 232 (338) is.
2000 (in mill 60 227 (321) 0 OPEB Pans 2 2002 ions) 34 114 (62)
(8)
(8).
29 13 (24)
, (69)
(39)
(68)
.2001 2000
$ 30 S 29 114 106 (61)
(57) 30 41 27
-18 4
142 131 123 1
79 S=-M)
L-fi)
S14 ma sao (a) Curtailment charges were recognized during 2000 for the shutdown of central southern ohio coal company an windsor Coal company.
- 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:
-=
' 'S ' t.
U.S.
X '
.. ' ' U.S' Pension Plans OPEB Plans APCo CSPCo I&M KPCo I
I OPCo PSo I:
SWEPCo -
TCC TNC other Non-Regist subsidiaries Total rant 2002 2001 2000 2002 2001 2000
- t (in thousands)
$ (9,988)
S(13 645) $(14,047) $ 25 107
$ 22,810
$ 22,1:
(8;328)
(10,624)
(10,905) 11 494
. 10,328,: 9 6 (4,206)
(7 805) ' (8,565) 17,608 15,077 14.1 (1,406)
(1,922)
.(2,075) 2,986.
2,438 ~2,31
.(11,360)
-(14,879)
(15,041)
' 22,608.,34,444 116,21 (3,819)
.(2,480)
(2,196) 8,436 6,187 '
4,2i (2,245)
- (3 051)
(2,606) 8,371-6399 4l' (4,786)
(3411).:- (2,986) 10,733'.
8,214 6,6' (1,104)
(1,644)
(1,585) 4,798 3,729
.2,9:
I.,.
39
- 43.
55 54,
!05 ":.
77 52 56
.. I -
B29' 3;657 (9,139 (7.546)-9 22 22 278
'19 798
$ (3, 8s)S (8,00)- $(67 14MB6 2f 3.E
The weighted-average assumptions as of December obligations are shown in the following tables:
31, used in the measurement of AEP's benefit
-Discount Rate Expected Return on Plan Assets Rate of compensation Increase.:
U.S.
Pension Plans 2002
- 2001
- 2000
- 6.75 7.25 7.50 9.00 9.00 3.7 3.7 I
, U.S
¢ OPEB Plans I
2002 2001 2000
.6.75 7.25 7.50.-- '
9.00
. 8.75
.8.75 8.75.
3.2 N/A N/A N/A L-63
1-I determining the discount rate in the calculation-of future pension obligations we review the
interest rates of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. As a result of a decrease in this benchmark rate during 2002, we determined that a decrease in our discount rate from 7.25% at December 31, 2001 to 6.75% at December 31,-
2002 was appropriate.:
For OPEB measurement purposes, a 10% annual rate of increase in'the per capita cost of covered health care benefits was assumed for 2003. The' rate was assumed to decrease gradually each year to a rate of 5% through 2008 and remain at that level thereafter.
Assumed health 'care cost trend: rates' have' a significant effect on the amounts reported for the OPEB health care plans.
A 1% change in assumed health care cost trend rates would have the following effects:
1% Increase 1% Decrease (in millions)
Ettect on total service and interest cost :
components of net.
periodic postretirement health care benefit cost Effect on the health care component of the accumulated postretirement benefit obligation AEP Savings Plans AEP sponsors various de retirement savings plans eligi all non-United Mine Workers c U.S. employees. These plar under Section -401(k) of the Code and provide' for c
$ 21 ontributions. :-LBeginning in 2001, AEP's contributions to the two largest plans increased to 75 cents for every dollar of the first 6% of eligible employee compensation from the pre'vious rate of 50 cents. The cost for contributions to these plans totaled $60.1 million in 2002, $55.6 million
,in 2001 and $36.8 million in 2000.
The' following table provides the cost for contributions to the savings plans by the following AEP registrant and other. non-registrant subsidiaries for fiscal years 2002, 2001 and 2000:
2002 -
2001 2000 (in thousands) csPco I&M
- KPCo OPco
.I I
r PSO I
SWEPCO TCC
- TNC I
Ahr mnn-
$ 6,722 2,784 8,039
- 1,043 5,785-2,260 -
2,765
- 3,054 1,574
$7,031 2,789:
7,833 1,016 1.6,398 2,235
- 2,776 3,046 1,558
$ 3,988 1,638 4,231 544 3,713
- 2,306 2,880 3,161 1,708
-:Registrant subsidiaries 26.094 20 869 12.677 Total.
60120-4 On January 1, 2003, the two major AEP Savings
-Plans merged into a single plan.
(17) Other UMWA Benefits AEP and OPCo provide UMWA pension, health and welfare benefits for certain unionized mining 237 (193) employees, retirees, and theirsurvivorswho meet eligibility requirements.
The benefits are administered by UMWA trustees and contributions are made to their trust funds.
3fined contributioni -
f Contributions are expensed as paid as part of ible to substantially the cost of active mining operations and were not fAmerica (UMWA) material in 2002, 2001 and 2000. In July 2001, ns includeMfeatures OPCo sold certain coal mines in Ohio and West
'Internal Revenue Virginia..
ompany 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 prce 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 ls following
.L-64
the first,' second and third anniversary of th rant date.
CSW maintained a stock option plan prior to the merger, with AEP in 2000. Effecti'e With the. m9rger, l CSW stock options outstanding were converted into AEP stock options at an! exchange ratio of one CSW stock option for 0.6 of a'n 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. Underthe 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 veteuonth cmletion of themegrndxpe 1 0 years after their original grant date.:
Asummary of AEP stock option transactions in fiscal periods 2002, 2001 and 2000 is a's follo'ws:
2002 2001 2000 weighted
_-7Wei ghted Weighted Averaqe
~
Average Average.
Options Exercise Opti ons Exercise Option Exercise' (in thousands)
Price; (in thousands) -price (Jin thousands). Price uutstanaing at beginning of year 6,822 Granted..
2,923~
Exercised (600)
Forfeited(3
)
~end of.year 6
Z optio-ns exercisable
- at end of year, -A weighted'average Exercise price of options:,
-Granted above arket Price
-Granted at arket Price
~$37
~$27
$36
$41
$34
$36
$27
$27
,6,610
,645 (216)
(217)
$36
$45
$38:
$37
$37,
$43 825
-$40 6,046
$36 (26)
$36 (235)
$39
$36, 5H
$41 11 1:IIN/A 11
.$45
.1N/A
$36 The following table summarizes inform-ation about AEP stock options outstanding at December 31, 2002:
Otptions outstainding Range.of Exercise Number-Life in~ Exercise Prices Outstanding Years, Price
$27.06-35.625, 8,047,058 8.4,
$ 3.54 40.69-49.00 739.483 7.1
~44.84
$27.06-49.00 8,786 41 8.3
$ 3.58 op3tions Eercisable Range of Exercise Number weighted-Average Prices outstanding Exercise Price
$27.06-35.625 2,230,000
$35.51' 40.69-49.00 251.37 4366
$27.06-49.00 2,481.337
$536.33 If compensation expense for'stock options had been determined based on the fair value at the grant date, AEP net income and earnings per share would have been the pro forms amounts shown in the following table:
Net (loss) income:
.As reported Pro.forna
- Basic (loss) earnings prshare:
As reported Pro frmna Diluted (loss) earnings per share:
As, rePorted Pro forma,-
(in mllions except per sare amounts)
$ (519),
$ 971, $ 267 (528) 959 264 I5$(I.57)
(1.U:59)
$3.01 2.98
$0.
83 0.82
( 57)
$3.01
$0.83
.:59) 2.97 0.82 The proceeds, received from exercised stock options are included in common stock and paid-in capital.
.The pro forms amounts are not representative of the effects on reported net income for future years.
$37
$36
-825
$40 645 61046 336
$36 (216)
$38 (26)
$36
$41 (217
$37 (235)
$39
$34
- 437,
$36,
$36
$43
$41
The fair value of each option award is estimated.
on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used to estimate the fair.
value of AEP options granted:
2002 2001 2000 Risk Free Interest Rate 3.53%
4.87%
-5.02%
Expected Life 7 years 7 years 7 years Expected Volatility 29.78%
28.40%
24.75%
Expected Dividend Yield 6.15%
6.05%
6.02%
weighted average fair value of options:
-Granted above Market Price
$4.58 N/A N/A
-Granted at Market Price
$4.37
$8.01
$5.50
- 16. Business Segments:
In 2000, AEP reported the following four business segments: Domestic Electric Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and Other.
With this structure, our regulated domestic utility companies were considered single, vertically-integrated units, and were reported collectively in the Domestic Electric Utilities segment.
In 2001 and 2002, we moved toward a goal of
' functionally and structurally separating our businesses. The ensuing realignment of our operations resulted in our current business segments, Wholesale, Energy Delivery and Other.
The business activities of each of these segments are as follows:
Wholesale Generation of electricity for sale to retail and wholesale customers
-- 'Gas pipeline and storage services
' g Marketing'and trading of electricity, gas, coal and other commodities
- ;,Coal mining, bulk commodity barging operations and other energy supply related businesses Energy DeliverX Domestic electricity transmission, Domestic electricity distribution' Other Energy services Segment results of operations for the,twelve months ended December 31, 2002, 2001 and 2000 are shown below. These amounts include' certain estimates and allocations where necessary.
We have used earnings before interest and income taxes (EBIT) as a measure of segment operating performance. The EBIT measure is total operating revenues net of total operating expenses and other income and deductions from income. It differs from net income in that it does not take into account interest expense, income taxes and the effect of discontinued operations, extraordinary items and the cumulative effect of a change in accounting principle. EBIT is believed to be a reasonable gauge of results of operations.
By excluding interest expense and income taxes, EBIT. does not give guidance regarding the demand -of debt service or' other interest requirements, or tax liabilities or taxation rates.
The effects of interest expense and taxes on overall corporate performance can be seen in the Consolidated Statements of Operations.
By excluding discontinued operations, extraordinary items, and the cumulative effect of changes in accounting principles, EBIT gives more focused guidance on segment operating performance.
'ri i '
.i i
. I -.. i I.
Year 2002 Revenues from:
EXternal unaffiliated customers
.$10,988 Transaction with other operating segments 2,p314 Segment EBIT 645 Depreciation, depletion and amortization expense 842 Total assets 22,622 Investments in equity method~
subsi di ari es 115
- .Gross,property additions 1,072 2001' Revenues from:
External unaffiliated customers
$ 9,297 Transactions with other:
operating segments 2,708 Segment EBIT 1,302 Depreciation, depletion and' amortization expense 597
.Total assets 21,947 Investments in equity method subsidiaries
,242 Gross-property additions 610 2000 Energy Reconciling wholesale Deiey Other Adiustments (in mill1ions)
$ 3, 551
$ 16 20 46 970.
(549):
519 16 11,624 248 57' 68 12
$ ~3,356
~~'20
" -986.
.632 12,, 45 5 844-114 1, 155;-
42 14 220
.370.
200 (2,380) 247(a)
(3,883) 4,675(a)
-AEP Consolidated:.
$14, 555 1,066 1,377
~34,741 172 1,722
$12, 767, I12,330 1,243 39,297
,.612 1, 654 Revenues from::
~External unaffili ated customers.$
7,834
$3,174
$ 105
$11,113 Trransactions-withote operating segments 1,726
- 2.
750 (2,478)-
Segment EBIT 686 1,017 89
-1,792 Depreciation, depletion and amortization expense 556 506 29 I
1,091 r
Total assets-24,172
~14,8. ~2,625 '
490a)4,3 investments in-equity method subsi di ari es -
140
-296 436 Gross property,additions' 366
'961 141 1,468 (a) Reconciling adjustments for Total ASsets include AssetS H'el dfor 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 seg ment 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 AEG Co's financial statements.
- 41 ".
I q -.
a I
I.
I
- z.
I.
I.I
Twelve Months Ended December 31, 2002 Twelve Months Ended
! December 31. 2001 Wholesale Segment APCo
- CSPCo, I&M KPCo OPCo PSO SWEPCo TCC TNC Energy Delivery Segment APCo CSPCo l&M KPCo OPCo PSO SWEPCo TCC TNC Segment Revenues EBIT (in thousands)
$1,220,381
$215,735 907,882 282,974 1,205,043 42,410 246,629, 6,568 1,523,452 364071 518,100 34,322 736,484 70,547 1,135,946 395,060 377,387 (58,930)
$ 594,089 492,278 321,721 132,054 589,673 275,547 348,236 554,547 73,353
$217,360 63,071 170,342 51,697 71,225 69,543 107,081 148,918 53,995 Registrant Subsidiaries Company Total APCo CSPCo I&M KPCo OPCo PSO SWEPCo TCC TNC
$1,814,470
$433,095 1,400,160 346,045 1,526,764 212,752 378,683 58,265 2,113,125 435,296 793,647 103,865 1,084,720 177,628 1,690,493 543,978 450,740 (4,935)
$4,627,847 2,753,240 4,587,191 1,164,676 4,457,032 1,776,690 2,208,675 5,356,438 877,175
$1,784,259 1,350,319 1,526,997 379,025 2,098,105 957,000 1,101,326 1,738,837 556,458
$378,577
$4,482,785 362,875 2,722,388 228,602
- 4,394,062 58,968 999,048 358,389 4,394,073 131,873 1,748,911 189,606 2,300,676 413,553 4,893,030 41,156 864,875 L-68 Total Assets
$2,586,966 1,762,074 3,160,575 591,655 2,861,415 840,374 1,082,251 3,117,447 376.308
$2,040,881 991,166 1,426,616 573,021 1,595,617 936,316 1,126,424 2,238,991 500,867 Revenues
$1,189,223 867,100
. 1,212,587 247,842 1,545,392 695,123 768,322 1,265,655 387,422
$ 595,036 483,219 314,410 131,183 552,713 261,877 333,004 473,182 169,036 Segment EBIT (in thousands)
$164,844 232,372 117,396 4,935.
-240,128 52,086 82,409 303,966 7,930
$213,733 130,503 111,206 54,033 118,261 79,787 107,197 109,587 33,226 Total Assets
$2,505,877 1,742,328 3,027,509 507,516 2,820,995 1 827,235 1,127,331 2,847,743 371,031
$1,976,908 980,060 1,366,553 491,532 1,573,078 921,676 1,173,345 2,045,287 493,844
Twelve Months Ended December 31. 2000 Revenues Segment ESIT Total Assets (in thousands)
Wholesale Segment APCo'
$118,35-$154,525
$3,674,081 CSPCo 906,363
.235,660
-2,481,594 l&M
.1.177,190~
(146,297) 3, 978,360 KPCo 268,529~
22,379 759,228 OPCo A62742904
.3,976,532 PSO 711,274 54,072 1011,474:
-SWEPCo:
773,324
.27,055 1,302,611 TCC 1,291,588 273,650 3,182,202, TNC 394,860; 13,91 0 466,539,
- Energy Delivery Segment APCo 574,918.
$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
~~~~~~~~~467,587 138,4182,143 P3O 245,124 85541,126,949 SWEPCo 344,950 129,842.1,355,778 TCC 478,84 1'36,069 2,285,499 TNC 176,204 50,201 620,965 RAr,kfrant timhtiirtpq Company Tota.
- APCo
$1,759,253 CSPCo 1,304,409 l&M
.1,488,209 KPCO 389,875 OPCo 1
2,140,331 PSO 956,398 SWEPCo
.1,118,274
-~ ~~~TC
~~-1,770,402
$346,085 317,756 (20,056) 72,149, 427,502 139,596 156,897
' 409, 719 69.
$6,572,595 3,877,491 5,774,108 1,494,543 6,193,975 2,138,423 2,658,389 5,467,701 1,087,504
, I., I t,
I. '.1
- ~~~7 Risk M anagemen't,-',
Financial,'
- 17. Risk Management, Financial,--'
Instruments and Derivatives::-
-Risk Management' We are subject to market risks in our day tc day operations. Our risk policies have beer reviewed with the - Board of Directors approved by a Risk Executive Committee anc are administered by the' Chief Risk Officer The Risk Executive Committee establishes
' risk limits, approves risk' policies, -assigm responsibilities regarding the oversight anc management of risk and monitors risk levels This committee receives daily, weekly, anc monthly reports regarding compliance witl policies, limits and procedures.
Th(
committee meets monthly and consists of thE Chief Risk Officer, Chief Credit Officer, V.P. o Ma'rket Risk Oversight, and senior financia and operating managers.
-The risks and related strategies tha management can empioy are:
Risk Description Price Risk
.Volatility in commodity prices Interest Rate Risk Changes in interest rates Foreign Exchange Fluctuations in Risk foreign currency rates Credit Risk Non-performance on contracts with counterparties Strategy Trading and hedging Hedging Trading and hedging; I Guarantees and I:
collateral:
We employ physical forward purchase an(
sale contracts, exchange futures and options over-the-counter options, swaps, and othe derivative contracts to offset price risk when appropriate. However, we engage in tradini of electricity, gas and to a lesser degree othe commodities and as a result we are subject tF price risk: The amount of risk taken by thi traders is controlled by the management c the trading operations and the Chief Ris]
Officer and his staff. If the risk from tradin!
activities '-exceeds certain pre-determinei limits, the positions are modified or hedged tF reduce the risk to be within the limits unles specifically approved by the Risk Executiv Committee.
AEP is exposed to risk from changes in th market prices of coal and natural gas used t generate electricity where generation is n longer regulated or'- where existing fu(
clauses are suspended or frozen.
-Th protection afforded by fuel clause' recovery mechanisms has either been eliminated by the implementation of customer ctioice in Ohio (effective January 1, 2001) and in the, ERCOT area of Texas (effective January 1, 2002) or frozen by a settlement agreement in
-Michigan, capped 'in Indiana and-fixed
-' '(subject to future commission action) in West
.:,.,Virginia. To the extent all fuel supply for the i-' generating units in these states is not under fixed price long-term contracts, AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Arkansas, Kentucky, Louisiana, Oklahoma, Virginia and the SPP area of Texas.
We enter into currency and interest rate f
forward and swap transactions to hedge the currency and interest rate exposures created by commodity transactions.
These transactions are marked-to-market to match t
the change in value in the transactions they hedge which are also marked-to-market. We employ forward contracts as cash flow hedges and swaps as cash flow or fair value
'hedges to mitigate changes in interest rates or fair values on Short-Term Debt and Long-term' Debt when management deems it necessary. We do not hedge all interest rate
- risk.
We employ cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where:' deemed r,;-
-'necessary.-
International subsidiaries use Sr j. currency swaps to hedge exchange rate fluctuations in debt denominated in foreign
-currencies.
We do not hedge all foreign r:
_,currency exposure.
- Our open trading contracts,: including structured transactions, are marked-to-market Fk daily using the price model and price curve(s) corresponding to the instrument. Forwards, futures and swaps are generally valued by subtracting the contract price from the market s:
X price and then' multiplying the difference by e - 'the contract volume and adjusting for net
'present value and other impacts. Significant estimates in valuing such contracts include forward price curves, volumes, seasonality,
° ' - -'weather,'and other factors.
0 Forwards and swaps are valued based on e
L-70'-
7 7
forward price curves which represent a senes,.
costs. Also, an'energy commodity contract's 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 market's 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 bidprice, which is the 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 primarly of (credit risk) and liquidity risk.
options on forwaras ano spreau opuois, Olt; valued using models,'which are variations on Black-Scholes option models. The market-related inputs are the interest rate curve, the underlying commodity forward price curve,,
the implied volatility curve and the implied correlation curve. Volatility and correlation prices may be quoted in the market.
Significant estimates in valuing these'--
contracts include forward price curves, volumes, and other volatilities.
Futures and options traded-on exchanges (primarily oil and gas on NYMEX) are valued at the exchange price.
We'also mark-to-market derivatives that are
-not trading contracts in accordance with generally accepted accounting principles.
There may be unique models for these transactions, but the curves' the Company inputs into the models are the sameforward curves, which are described above.
We have
.evaluate t
' models a
. inherent assumptic
- -open long there cot Electricity and gas markets in particular have adverse e primarytrading hubs ordelivery points/regions and cash and less liquid secondary delivery points. In differ frorr North American natural. gas markets, the primary delivery points are generally traded Results o from Henry Hub, Louisiana. The less liquid gas or power trading'points may trade as a The amoi spread (based on transportation costs,
- less purcl constraints, etc.) from the nearest'liquid' trading ac trading hub. Also, some commodities trade more often and therefore are more liquid than others.
For example, peak electricity is a Net Revel more liquid product than off-peak electricity.
Margins Henry Hub gas trades in monthly blocks for up to 36 months and after that only trades in.
The amo seasonal or calendar blocks.: When' this 2001 and occurs, we use our best judgment to estimate
--were:
the curve values. 'The value used will be based on various factors such as last trade APCO price, recent price trend, product spreads, cspco:
location spreads (including transportation
' KPCO costs), cross. commodity spreads (e.g., heat opco rate conversion of gas to power), time SWEPCo spreads, cost of carry (e.g., cost of gas TCC storage), marginal production cost, cost of Total new entrant capacity,' and'alternative fuel L-71 ieveloped independent controls to
-Le reasonableness of our valuation nd curves;: However, there.are risks-. related to the underlying Mns in models used to fair value
-term trading contracts. Therefore, ild be a' significant favorable or ffect on future results of operations flows if market prices at settlement n the price models and curves.:
f Risk Management Activities ints of net revenue margins (sales lases) in 2002, 2001, and 2000 for ctivities were:
2002 2001 2000 (in milions) nue
$53.
$402
$233 unts of revenues recorded in 2002, d 2000 for the registrant subsidiaries 2002
. 01 20
- 2002
- 2001 (in thousands)
$29,044
$52,871 24,503 36,120 11,833 19,130 3,801 6,150 39,114 43,789
.: (1,357)
(7,345)
(4,999)2.
2,317 (7,708) 10,500 (1,098) 1,508 zout) 27,924 -
16,999 26,575 10,704 26,840 5, 233 1,562 1,752) 222 S14,307
The fair value of open trading contracts that are marked-to-market are based on management's 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:
2Afl) 7nni Trading Assets, Electricity and other Physicals, Financials Total Trading Assets Gas Physicals I
Financials Total Trading Assets Fair val ue (in miTlions) '
$ 846 226
-$S 105 685
-i Fair Value (in' millions) 966.
1 i 1 170 S : 196 1 587 Trading Liabilities Electricity nds othe Ph ysicals Financials Total Trading Liabilities S (534)
(126) 1Q)
$ (760)
' :(87)
. K:M Gas Physicals (191)
$ (38)
Financials (761)
(1586 Total Trading Liabilities S$1,624)
The fair values of trading contracts for the registrant subsidiaries at December 31 are:
2002 Fai r value (in thousands)
APCo Trading Assets Electricity and other Physicals S 168,687 Financials 39,585 Trading Liabilities Electricitv and other Physicals
-(100,045)
Financials (11,375)
- CSPCo I
Trading Assets Electricity ad other
~~Physicals Financials
- Trading Liabilities
$ 113,397 26,611 2001 Fai r value (in thiisands)
S 217,914 39,466 S(164,624)
(17,055)
$ 133,425 24,206 Electricity and other Physicals Financials I&M
-Trading Assets
,'lectricity and other Physicals Financials
','Trading Liabilities
- ; Electricity and other-i
~~Physicals Financial
- *. $ (67,244)
(7,647)
$ 121,706 I-.
28,474 S (70,061)
(9,258)
/
$ (98,749)
(10,433)
$ 165, 162 26, 630 i (117,795)
(12,652) 11
KPCo Tradi nc Assel Electriity,
irauinu LiaD 2002 ai r value ind other
- hysicals
$43,532 Financials 10,216
[litis
.Physi ca]I Fi nanci~
oPco Tradi ng Asts Electricity ad 0thi Physi cal Fi nanci ~
Trading Liabilities Financii
.PSO:
Trading Assets Electricity Physica Trading Liabilities Physica' SWEPCo raigAssets Phy'si ca Trading Liabilities Electricill Is i
Is 115s I,. $
(2 5:815) 158,473 3 5,304.
S C89,526)
(10,145) ~
2001 Fai r value C n, thou-sands) 53,651' 9,732
$ C46,476 (4,178)
$ 180,989 32,997 S (132,603) '
(15,937)
I s S
8,165
$47, 613 Is 5- (4,620)
$ (45,179)
Is
~
9,329
$ '54,647:
Is.
(5,278),
$ (51,747),
Physicals
$ 26,752
$62,520 Trading Liabilities Physicals
$ (21 136)
$ (58,663)
Trading Assets..
Physicals
,2 3
$ 18,567 Trading Li abi1ii es Physicals S (4 047)
$(17,652)
Financials
~,233)
L-73 I i
,.7 " -
I I.
I
.I I i I
Credit Risk AEP limits credit risk by extending unsecured credit to entities based on internal ratings.
AEP uses Mood/s Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess Ithe financial health of counterparties on-an ongoing basis.
This data, in conjunction with the ratings information, is used to determine appropriate risk parameters.
AEPalso requires cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.
brokerage accounts with brokers who are registered with the U.S. Commnodity Futures' Trading' Comission.
Brokers and counterparties require cash or cash-related instruments to be deposited on these transactions as margin against open positions. The combined margin depbsits at December 31, 2002 and 2001 were $109 million and $55 million.
These margin accounts are restricted and therefore are not included in Cash and Cash Equivalents on the Consolidated Balance Sheets. AEP and its subsidiaries can be subject to further margin requirements should related commodity prices change.
pte s
h cmie margin deposits at Deebr3,20 We trade electricity and gas contracts with numerous counterparties.
Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty are not material to ourfinancial condition at December 31, 2002.
At December 31, 2002, less than 7% of our exposure was below investment grade as expressed in terms of Net Mark to Market Assets.
Net Mark to Market Assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty.
The following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments at December 31, 2002:
Counterparty Credit Quality AAA/Exchanges AA A
BBB Below Investment Grade
- Futures, Forward and Swap Contracts Option1 26 307 448 700 107.
(in millions)
$ 2 33 26 101 Total 28 340 474 801 11 118 Total
$S173 S1,761 We enter into transactions for electricity and natural gas as part of wholesale trading.
operations. Electricity and gas transactions are executed over-the-counter with counterparties or through brokers.
Gas transactions are also executed through The margin deposits at December 31, 2002 for the registrants were:
(in thousands)
APCo CSPCo I&M KPCo OPCo PSO SWEPCo TCC TNC
$1,010 673 727 261 1,400 91 105 121 37 Financial Derivatives and HedQinq In the first quarter of 2001, AEP adopted SFAS
- 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
AEP recorded a favorable transition adjustment to Accumulated Other Comprehensive Income of $27 million at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives included in the transition adjustment are interest rate
- swaps, foreign currency swaps and commodity swaps, options and futures.
Most of the derivatives identified in the trans-ition adjustment were designated as cash flow hedges and relate to foreign operations.
Certain derivatives may be designated for accounting purposes as a hedge of either the fair value of an -asset, liability, 'firm commitment, or a hedge of the variability of cash flows related to a variable-priced asset, liability, commitment, or forecasted trans-action. To qualify for hedge accounting, the L-74 11 I
relationship between the hedging instrument '
SFAS 133 are recognized currently in and the hedged item must be documented to; r: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 whether the 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 l
Consolidated Balance Sheets at December 31,'2002 are:
-Accumulated ot other comprehensive Hedging Assets Hedgind Liabilities Income (Loss)
After-Tax (n mil ions)
Electricity and Gas 6
$ (8)
(2)
Interest Rate (13)*
(12)
Foreign Currency (2)
.(2)
- Includes $6 million loss recorded in anFequity,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:
I..1.
- in millions).
AEP Consolidated Beginning Balance, January 1, 2002
.changes in fair value.
Reclasses from OCI to net loss Accumulated OCI derivative loss December 31, 2002 APCo Beginning Balance, January:1, 2002 Eftective portion of changes in fair value
-.Reclasses from ocI to net income:.
Accumulated oci derivative loss, December 31, 2002 CSPCo-Be aeinning Balance, January 1, 2002-Effective portion of changes in fair value Reclasses from OCI to net income Accumulated OCI derivative loss, December 31, 2002' I&M Beqinning Balance, January 1, 2002 Effective portion of changes in fair value Reclasses from OCI -to net income Accumulated Oci derivative loss, December.31, 2002 KPCo Beginning Balance,-January 1,2002 Effective portion of changes in fair value Reclasses from OCI to net-income Accumulated CCI derivative gain, December 31,' 2002 oPCo Beginning Balance, January 1, 2002 Effective portion of changes in fair.value Reclasses from OCI-to net income Accumulated OCI derivative loss, December 31, 2002 Pso Beginning alance, January 1, 2002 Effective'portion of changes in.fair value.
- Reclasses from oci.to net income --
- Accumulated Oci derivative loss, December 31,' 2002 L-75 (3)
(56) 43 (in thousands)
S (340)
(1,310)
(270) 62 (3,835) 34 3.515 S (1, 903) 343 1 882 (196)
(103)
(439)
$ -(38) 2 (44)
(in.thousands)
I *1 -j~
1 (49)
S (484)
SWEPCo BeBinning Balance, January 1, 2002 Effective portion of changes in fair value Reclasses from OCI to net income
-Accumulated ocI derivative loss, December 31, 2002 TCC Beinning Balance, January 1, 2002 Effective portion of changes in fair value Reclasses from ocI to net income-Accumulated ocI derivative loss, December 31, 2002 TNCBaae,1 Beginning Jalance January 1, 2002 Effective portion of changes in fair value Reclasses from ocI to net income Accumulated OCI derivative loss, December 31, 2002 S
30
(__66)
-. 3 t18)
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 fair values of significant financial instruments for AEP and its registrant subsidiaries at December 31, 2002 and 2001 are summarized in the following tables.
AEP Long-term Debt Preferred stock Trust Preferred securities AEGCo Long-term Debt APCo Lon term Debt Preferred stock CSPCo Long-term Debt Preferred stock I&M Long-term Debt Preferred stock KPCO Long-term Debt opco Lon -term Debt Preferred stock 2002 Book value Fair Value (in millions) 10,125
. 84 321 S 10,470 77 324
.(in thousands) 2001 Book Value Fair value (in millions)
S..
9,505 S
95 321 (in thousands)
S 44,802 48,103 S
44,793 $
45,268
$1,893,861
$1,953,087
$1,556,559 10,860 9,774 10,860
$ 621,626 S 643,715 S 791,848 10,000
$1,617,062 _S1,673,363
$1,652,082 64,945
- 58,948 64,945
- $ 466,632
$1,067,314
$1,
.8,850 L-76 475,455
$ 346,093 095,197 - $1,203,841
-7,965
. :8,850
$1,439,531 10,860
$ 802,194 10,100 S1, 672, 392 62,795 S 350,233
$1,227,880 8,837 9,542 -
93 321 I l I a E I
PSO Long-term Debt S
545,437 570,761 S
451,129
$ 462,903 Trust Preferred Securities -
.75,000 75,900 75,000 74,730 SWEPCo Long-term Debt
$ 693,448 S 727,085
$ 645,283 S
656,998 Trust Preferred securities 110,000 110,880 110,000
- 109,780 TCC Long-term Debt
$1,438,565
$1,522,373
$1,253,768
$1,278,644 Trust Preferred Securities 136,250 136,959 136,250 135,760 TNC Long-term Debt 132,500
$ 144,060
$ 255,967: S 266,846 Other Financial nstruments - 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.
oAA) rr1 AAA Federal:
Current Deferred Total State:
Current
- Deferred Total International:
Current Deferred Total Total Income Tax as Reported Before Discontinued operations,
-Extraordinary Items and.
cumulative..
Effect (in mill ions)
$ 330
'$404 S 793 (192) 60 (236) 138 464 557 32 61 47 30 34
(
7-62 95 41 13-(13) 4 1 -
4
-: ~
~
13 4
i,
-. : i, 1
1 -
oY
,. E
, 4 0 iSM
' 0
?
L 7
Th deal of th regstan susdire inom tae asrpre
- rsflos
/:
l
- ~ ~
~ ~ ~ ~ ~ ~
EL p::L L
r;L::
Year Ended December 31, 2002 charged (credited) to operating Expenses (net):
Current Deferred Deferred:Investment Tax credits Total charged (credited) to Nonoperating Income (net):
Current Deferred Deferred Investment Tax Credits Total Total Income Tax as Reported
- Year Ended December 31,-2002 charged (credited) to operating Expenses (net):
current Deferred Deferred Investment Tax credits Total charged (credited) to Nonoperating Income (net):
current Deferred Deferred Investment Tax credits Total Total Income Tax as Reported
$ 6 607 (5,028)2 1.581 (173)
(3.
363)
(3 536)
L=Xa OPCo S 86,026 30,048 (2.493) 113. 581 2,732 15,962 (684) 18,010 S13,59 KPCo (in thousands)
S 99,140 17,626
--3.22 9) 113. 5 37 (354)
(849)
(1.408)
(2.611)
$ 81,539 S 66,063 25,771' (19,870)
(3.096)
(7.340)
_104.214 38.853
.9,442 (2,479)
(174) 6.789 3,435 2,949 (400) 5.984
$4&
A4Z PSO SWEPCo TCC (in thousands)
S(49,673) 75,659 (1.791) 24.195 (1,812)
(_._2
$S 41,354 (3,134)
(4.524) 33.696
.1,772
_L AO S 30,495 113,726 (5.207) 139.014 3,223 (71) 3.152 I-i_166 S
680 9,451 (1.173) 8.958 1,583 388 (67) 1.904 S 10,862 TNC g
109
-(10,652)
(1.271)
(11. 814) 1,334 (1,623)
Year Ended December 31, 2001 charged (credited).to operating Expenses (net):
current Deferred Deferred Investment Tax credits Total charged (credited) to Nonoperating Income (net):
Current Deferred Deferred Investment Tax credits Total Total Income Tax as Reported AEGCO S 9,126 (6,224) 2,902 (56)
(3.414)
(3.470)
S (568)
APCo CSPCo I&M (in thousands)
S 71,623 S 88,013
$ 107,286 27,198 14,923 (45,785)
(3,237)
(3,899)
(7,377) 95.584 99.037 54.124 (19,165)
(13,803) 21,832 17,885 (1.528)
(159) 1,139 3,923 (10,590) 16, 580 (947) 5.043 S -59 167 KPCo
$. 7,726
. 2,812
- (1.180) 9.358 (2,725)
. 3,481 (72) 684 Year Ended December 31, 2001 charged (credited) to operating Expenses (net):
Current Deferred Deferred Investment Tax credits Total charged (credited) to Nonoperating Income (net):
Current Deferred Deferred Investment Tax credits Total Total Income Tax as Reported oPco S (62,298) 166,166 (2.495) 101.373 (21,600) 20,014 (794)
(2.380)
$ 98,99 PSO SWEPCo (in thousands)
S 53,030 (16,726)
(1.791)
- 34. 513
$ 77,965 (31, 396)
(4.453) 42.116 352 542 TCC TNC
$ 190,671 (72,568)
(5.207) 112.896 (398)
(398)
S 19,424 (11,891)
(1.271) 6262 (691) 35 542A L-78
.j I&M11 AEGCLo
AEGCo APCO Year Ended'December 31; 2000 charged (credited) to operating-
- Expenses (net):
Current
~~~~~S 8,746 191 Deferred
.(5,842) 3,83~
Deferred investment:Tax Credits
-(2.94~
Total 2.904 130.051 charged (redited) to Nonoperating income (net):
Current (44) 32:
Deferred
-4,76,
.Deferred Investment Tax credits (3.39)
(1.96l Total
.(3.440) 3.121 7CSPCo I&M (n thousands) 5- $120,494 S 134,796.
B (7,746)
(126:748):
7~)-(.379)
(7.524) 109.369 524 7.
3, 777 3,683
- 7.
357 Total Income Tax as Reported Year Ended December 31, 2000 -'
- .SWEPCo (in thousands 2,950 1
I, 569
- (330) 4.~189-
-. TCC
- Charged (Credited) to perating
- EXpenses (net):-
- current 259,608 S11,597
$16',073
$ 89,0 6,774, Deferred:
(70,263) 25,453 14,653 1623 9,401 Deferred nvestment Tax redits (1,824)
_(17 9 1)
(4.482)
(5.207)
(1.271)
Total 187.521 35.259 26.244-100.459 14.904 charged (redited) to Nonoperating Income (net):
- Current-15,426 (1,306)
(1,476)
(5,'073)
(222)
Deferredi 4,307 (1,237)
Deferred investment'Tax Credits 1:75)
Total 136
(.7 ~
(503 145
'Total income Tax aS Reported
-M S_
5 L4 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 E1 2002 (in Net income (LOSS)
$ (519)
DiscontinUed operations (net of income tax of $73 million in 2002, $22 million in 2001 and $5 million in 2000) 190 EXtraordinary 'items (net of income tax of $20 million in 2001 and $44 million in 2000)
Cumulative Effect of Acounting change (net of.income tax of, $2 mill ion in 2001) 350 Preferred tock Dividends
.*.1 Income Before Preferred stock Dividends of ubsidiaries 32 Income Taxes Before Discontinued operations,".
Extraordinary tems and.'Cumulative Effect 214 Pre-Tax Income led DeceMber 1.
2001.
2000 imiTTions)
I S 971 (86)
.(18) 10 927 546
$267 ~- 1.1 (122) 35 t. 11
.1 191
-., 602,
- Im3 Income Taxes on Pre-Tax Income at Statutory Rate (35%).
86$
Increase (Decrease) in InCoMe Taxes Resulting from t Following Items:
Depreciation
.32 corporate wned Life Insurance Investment Tax Credits (net)
(35)
-Tax Effects of International Operations -
-123 Energy Production redits-(14)
Merger Transaction costs State Income Taxes 4
other 40--
(8 Total Income,Taxes as Reported Before Discontinued perations, Extraordinary.-.
Items and umulative Effect 214 Effective Income Tax Rate :
.L-79
~516 48
~~4 (37) _
(12) t62
-I5 )6
- KPCo
$17,878 2, 521 (1.187)
- 19. 212
~(50) 1,244 (65) 1.129 TNC
$278 77 247 (36)
~49 26 (38) 7
5133,179 -
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.'
Year Ended December 31, 2002 Net Income
,' IIncome Taxes Pre-Tax Income I AEGCo APCO CSPCO I&M I(in thousands)
$ 7,552
$205,492 S181,173 S 73,992 (1 955) 110.926' 111 003 44 837
-,Income Tax on Pre-Tax Income at Statutory Rate (35%).
'Increase (Decrease), in Income Tax Resulting from the Following Items:
Depreciation corporate owned Life Insurance Nuclear Fuel Disposal Costs Allowance for Funds used During construction Rockport Plant Unit 2 Investment Tax credit Removal Costs' Investment Tax Credits (net)
State Income Taxes other Total Income Taxes as Reported Effective Income Tax Rate Year Ended December 31, 2002 Net Income (Loss)
Income Taxes Pre-Tax Income (Loss)
Income Tax on Pre-Tax Income (Loss) at statutory Rate (35%)
Increase (Decrease) in Income Tax Resulting from the Following Items:
Depreciation Corporate owned Life Insurance Investment Tax Credits (net)
State Income Taxes other Total Income Taxes.as Reported Effective Income Tax Rate Year Ended December.31, 2001 Net Income Extraordinary Loss Income Taxes Pre-Tax Income Income Tax on Pre-Tax Income at statutory Rate (35%).
Increase (Decrease) in Income Tax Resulting from the Following Items:
'Depreciation corporate owned Life Insurance Nuclear Fuel Disposal costs Allowance for Funds used During Construction Rockport Plant unit 2 Investment Tax credit Removal Costs Investment Tax credits (net)
State Income Taxes other Total Income Taxes as Reported Effective Income Tax Rate S '1,959
$110,746 $102,262 S 41,590 S 11,000 870 3,082 2,899 21,812 (93) 719 268 (3,814)
(446)
(748)
(3,361) 33 5 (564)
. N_M955 2,057 305
~~.i 4!).i,)
'(735)
(4,637)'
(3,270)
(7,740)
' (1,240) 6,469 11,387 124 1,058 (4641) -(2.994) 3950 (1583)
S10 12 111,03 S4487 5-
,6 35.%
38.0%
37.7%
- 3.6S%
oPco PSO SWEPCo TCC TNC (in thousands)
S220,023
$ 41,060 S 82,992 S 275,941 S(13,677) 13 1
22 383-35 468 142,166 (12.103)
$123,065 S 22,205 S 41,461 S 146,337 S (9,023) 4,227 (84)
(3,177) 18,051 (10 491) 37.4%
(583)
(2,790)
(295)
(1,791)
(4,524)
(5,207) 2,639 3,987 2,202 (87)
(2.666)
(871) 3 29.9%
34.0%
AEGCo APCO '
' CSPCo I&M (in thousands)
S 7,875 (568)
$161, 818 96 723 (32)
(1,271)
_(200)
(1,5)
--KPCo
$161,876 S 75,788
$ 21,565
- 30,024,
102 960 59 167
- 10 042
- S 2,557 S 90,489
$103,201 $ 47,234
$ 11,062 230 2,977 450 (1,078) 374' (3,414)
(4,765) 1,050 9,613 (287)
(2.041)
S (s68) S_q6 N_AM 37_4%
2,757 21,224 544 (148)'
(3,292)
(1,606)
(4,058) 5,727 (5.211 34.9%
(-16'_137 (2,058) 5 59,16 1,581 334 (420)
(1,252)
(1, 581) 31.8 L-80 KPCO S 20,567 10 862 S 3,42
I -.
OPCO P0 SEC TCC TNC.
Year Ended December 31, 2001 (in'thousands)
Net Income
$ 147,445 $ 57,759. $ 89,367 ;$182,278
$ 12.32ff' EXtraordinary Loss 18,348 2,509-Income Taxes 98.993 34,86
- 42.658 12 498
-55 7 1 P re-Tax Income L~~
&~~~~~
Income Tax on Pre-Tax income at Statutory Rate (35%)
$ 92,675 $ 32,418 S 46,209 $,104,050
.$ 6,258 Increase (Decrease) in income Tax Resulting from the Following items:
Depreciation 18572 1-2
-51 8,7 1-6 Corporate wned Life Insurance 7,972 1,2 (51 8,7
-146 Investment Tax credits.(net)
(3,289)
(1,791)
_(4,453)_
(5,207)
(1,271)
State Income Taxes' 9,752 5 5137.
5,451 9,652.
1,283 other
.(9.969).
'(2.02)
(4.048)
(4.474)
(2.162)
Total Income Taxes a Reported.
5-M 8E 54.571 Effective Income Tax Rate L%.3 3L%
.h8.___
AGO APCo CSPCo I&M KC
'Year Ended December 31, 2000 (in thousands)
Net income (Loss)
S 7,984' $ 73,844.$ 94,966 $(132,032) $S 20,763 Extraordinary (Gains) LosS (1,066) 39,384-income TaX Benefit
(,7)
(14,148).
Income Taxes (536) 133 179 116.726 4.713 20 341 Pre-Tax Income (LOSS)
- 7448,
-Income Tax on Pre-Tax Income (LOSS) at tatutory Rate 35%)
$ '2,607 $ 69,330 $ 82,925 $ (44,562) I 14,386 Increase (Decrease) in ncome Tax
.Resulting from the Following items:
Depreciation 452
~~~~7,606 1529 20,378
.1,827 Corporate wned Life'Insurance.-
54,824 29,259 42,587 5,149 Nuc]ear Fuel. Disposal Costs---
(3,957)
Allowance for Funds used.
100 During Construction (07)(2,211)
Rockport Plant nit 2 Investment Tax redit 374 Removal osts
.(1,197)
(420)'
Investment Tax redits.(net)
(3,396)
(4,915)
(3,482)
(7,854)
(1,252)
State Income Taxes 784 9,950 89 6,004 1,597 other
~~8)
(2.419)
(254 (5.672)
(946)
Total Income Taxes as Reported Effective Income Tax Rate
- N.ML.
fiL2%
493%
. L~.
49.S%
opco PSO
.SWEPCo
.TCC TNC Year Ended December.31, 2000
.(in,thousands)
Net Income
~~~~~~$
83,737 $66,663
$ 72,672 $ 189,567
$ 27,450 Extraordinary Loss 40,157 Income TaX Benefit
.(21,281)
Income Taxes.
.20 67 33.953 24 768 9.8 13.445 P re-Tax Income income Tax on Pre-Tax Income
.at Statutory Rate (35%)
$ 107,902 $ 35,216 $ 34,104 $i 99,734
$14,313 Increase (Decrease) in Income Tax Resulting from the`Following Items:
- Depreciation
~~~~~~~27,577-.
695,-
(1,012) 7, 556 1,0 corporate wned Life nsurance 84,453 Investment Tax redits (net)
(3,398)
(1,791)
(482 (5,207).
(1,271)
State Income Taxes
(,8) 307 1,650 2, 296 other 86~7)...3 204)
(5.492),
8,93),
(801)
Total Income Taxes a Reported
'Effective Income Tax Rate.fiJ
.1 25A%
33.35%.
32L9%
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 Deferred Tax Liabilities Net Deferred Tax Liabilities Property Related Temporary Differences Amounts Due From Customers-For Future
.Federal Income Taxes Deferred State Income Taxes Transition Regulatory Assets Regulatory Assets Designated for securitization Asset Impairments and Investment value Losses Deferred Income Taxes on other Comprehensive Loss All other (net)
Net Deferred Tax. Liabilities
$ 2,189 (6,105)
,916)-
$(3,612)
(360)
(422)
(234)
(310) 417 326 279 I$_93_)
$ 1,-216 (5,716)
$(3,674)
(245)
(314)
(268)
(332) 3 330
$(450)
December 31, 2002 Deferred Tax Assets Deferred Tax Liabilities Net Deferred Tax Liabilities Property Related Temporary Differences Amounts Due From Customers For.
Future Federal Income Taxes Deferred state Income Taxes
-Transition Regulatory Assets Asset Impairments and Investment value Losses Deferred Income Taxes-on other comprehensive Loss Net Deferred Gain on sale and
. Leaseback-Rockport Plant Unit 2 Accrued Nuclear Decommissioning Expense Deferred Fuel and Purchased Power Deferred cook Plant Restart costs Nuclear Fuel All other (net)
Net Deferred Tax Liabilities AEGCo APCo CSPCo I&M (in thousands)
S 73,094 S 213,972 S
72,990 (102.096)
(915.773)
(510.761)
$ (74,291) $(555,824) $(331,381)
- 7,626 (58,246)
(5,119)
(77,693)
(28,735)
(8,895)
. (23,448)
(71,752) 18 215 38,823 31,961 38,866 (1,878) 3,916 (18.266) 34
$ (29,00)
$f08)
KPCo S 348,672 S
36,948 (704.869)
.(215261)
$(343,587)
$(127,073)
(38,752) -
(20,488)
(52,528)
(28,722) 225 4
21,800 25,860 65,856 (273)
(13,144)
(14,000)
.198)
(5,153)
.198)
(2.774) 7,77)$(3617 5,089 415 538)
December 31, 2002 b Deferred Tax Assets Deferred Tax Liabilities--
Net Deferred Tax Liabilities Property Related Temporary Differences Amounts Due From Customers For Future Federal Income Taxes Deferred state Income.Taxes, Transition Regulatory Assets Asset Impairments and Investment value Losses Deferred Income Taxes-on other comprehensive Loss Deferred Fuel and Purchased Power Regulatory Assets Designated For Securitization.
All other (net)
Net Deferred Tax Liabilities OPCo
$ 155,334 (949,721)
PSO SWEPCo (in thousands)
$ 70,649 82,113'.
(412.045).
(423.177)-
$ (341,396).$f3104
$(620,634) $(303,888)
(315,821)
- (53,256)
. (46,990)
(131, 833) 615 39,246 540 17 925
- $(9438) 9,490 (4,078)
(57,911)
(48,372) 2933 2890 29, 332 (28,696) 10.277 28,906 3,192 (4,891)
S. (709,246)
(198,595)
(66,333)
TNC 130,210
$ 35,970
- (1.391.462)
(153;49 )
$ (142,034) 5,726 (4,080)
- 14,996 39,394 16,565 2,655 (9,933)
(310,410)
(18.717) 1.239
$1,261,252)
$(11,521)
L-82 1
.December 31, 2001 Deferred Ta~~ ASsets Deferred Tax Liabilities Net Deferred Tax Liabilities~
PropertY Related Temporary Differences AmiountS Due From Customers'For FUture Federal-Income Taxes;-
Deferred state InCoMe Taxes Transition Regulatory Assets Deferred Income Taxes on other comprehensive LS Net Deferred Gain on sale and Leaseback-Rockport Plant Unit 2 Accrued Nuclear Decommissioning EXpense Deferred Fuel and Purchased-Power.'
Deferred cook Plant Restart Costs Nuclear Fuel All other (net)
Net Deferred Tax,Liabilities December 31, 2001 Deferred Tax Assets Deferred Tax Liabilities Net Deferred Tax Liabilities, PropertY Related Tempoirary, Differences Amounts Due From Customers For FUture Federal income Taxes
~Deferred State Income Taxes,
~Transition Regulatory Assets Deferred Income Taxes on other~
comprehensive LOSS Deferred Fuel and Purchased Power Provision for ine hutdown Costs iRegulatory AssetS Designated
~For ecuritization All ther (net)
Net Deferred TaX Liabilities
~We have settled with the IRS all issue returns for the years prior to 1991. We i years 1991 through 1996, and have filec for the years 1997 through 2000 are pre of any issues for open tax years that UPI effect on results of operations.:-
COLI Litigation - On February 20, 200 1, against AEP in its uit against the Unite consolidated federal income tax returnE the IRS' assertion that interest deductio and 1999 the Company paid the dispute for taxable years 1991-98 to avoid the pi contested tax. The payments were inc As a result of the U.S. District Court's c was reduced by $319 million in 2000.'TI decision with the U.S. Court of Appeals The earnings reductions recorded in 2C (in millions)
APCo
$82 I&M 66 KPCo OPCo 118 AEGCO APCO CSPCO I&M (in'.thousands)
S 75,856 $ 162, 334 S 74,767 -,$332,225 (103.831)
(865.909) 5148)U(732.756)
$ (70,`581) S(530,298) $(323,139) $(306,151) 922 (55,206)
(,3)
(46,756)
(3,822)
(56,747)
(8,968)
(38,015)
(34,783)
(78,298) 183 2,065 40,816
-27,157
~~~~43,707 (4,106)
(39)
(26,270)
(2~~~8,000)
~~~~~~~~~(16,02)
- oPCO PSO
.SWEPCoTC (in thousands)
$ 135,938
$ 59,421..5 56,189.$
130,863
.(93.87)
(356.298) (4597)
(1.294.658) 5(595,974) $(320,900)
- .(61,130).. 10, 199 (18,440)-
(35,038)
.(154,947).
5S(362,884)
.1(6,441)
(48,729) 1
- 30 6.
I
~~~112
- 3,052,
- (2,778) 20,323.1.~.
I-I I1 KPCo 30,927.
$ (118,147)
(20,215)
(25,267) 1,025 57 (5.757)
- TNC S$ *22,888 (167. 937)
- 5. :(808,922) $(149,309)
(70,174) 4,757 (66,333)
(4,079)
-18,032
~~(11, 7 56)
(3~~~~32,198) -
12 161l 45,810 51 051j 95.800.
15.338 s from the audits of our consolidated federal income tax iave received Revenue Agent's Reports from the IRS forthe I prote.sts contesting certain proposed adjustments. Retums sently being audited by the IRS. Management is not aware
- )n final resolution are expected to have a material adverse the U.S. District Court for the Southern District of Ohio ruled d States over deductibility.of interest claimed by AEP in its related to its, COLI program. AEP had filed suit to resolve ns for AEP.'s COLI program should not be allowed. In 1998 d ta'xes and interest attributable to COLI interest deductions otential assessment by the IRS of additional interest on the uded in other assets pending the resolution of this matter.
lecision to deny the COLI interest deductions, net income he Company has filed an appeal of the U.S. District Court's for the 6th Circuit.
100 for affected registrant subsidiaries were as follows:
L-83 z
v - -.,
I.
q
, 4..:,
',,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 Discontinued operations Income (Loss) Before Extraordinary Item And cumulative Effect Extraordinary Losses (net of tax):
Discontinuance of Regulatory Accounting For Generation Loss on Reacquired Debt cumulative Effect of Accounting change (net of tax)
Net Income (Loss) weighted Average shares:
Average Common shares outstanding Assumed conversion of Dilutive stock options (see Note 15)
Diluted Average Common shares outstandi ng
$ 21'
$' 917
$ 180 (1901 86 122 (169) 1,003 (48)
(2)
(350)
"Lm) 332 332.
Basi c and Di l uted '
Earnings Per Common share:
Income Before Discontinued operations, Extraordinary Items and'cumulative Effect -$
0.06 Discontinued operations (0.57)
Income (Loss) Before Extraordinary Item and cumulative Effect (0.51)
Extraordinary Losses (net of tax):
Discontinuance of Regulatory Accounting For Generation Loss on Reacquired Debt cumulative Effect of Accounting change
(
(net of tax)
'1.06) 18 322 1
-- 2M.
$2.85 0.26 3.11 (0.15)
(0. 01) 302 (35) 322
-;322
-U
$0.56 0.38 0.94 (0.11) 0.06
$3.01 L-84
- I r I
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 December 31, 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.
2 0.
Supl r
I n.
o,.
- 20. Supplementary nformation:'
AEP consolidated Purchased Power -
.,ohio valley Electric corporation (44.2% owned by AEP System).
cash was paid-for:
Interest (net of -capitalized amounts)
Income Taxes
- Year Ended Decemb'er 31.-
2002 2001-2000 (in millions)
$142.
.;$127.
$86
$792:
.- : $336 Noncash Investing and Financing Activities':-
Acquisitions under capital Leases Assumption of Liabilities Related to Acquisitions Exchange of communication Investment for common stock I$
.A
- $972
$569
$842
.$449 6
';$17
$118
.1 -
- $171 - :
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:
Year Year.
Year Ended December 31, Ended December 31, Ended December 31, 2002 APCo -
CSPCo.
I&M (in thousands)
$53,386 $14,885 $23,282 45,542 12,626 20,723
-- 30,998: '8,706 15,204 2001 2000
- 21. Power and Distribution Projects:-
I I.:.
Power Projects, AEP owns interests of 50% or less in domestic unregulated power plants with a capacity of 1,483 MW located in Colorado, Florida and Texas.
In addition to the domestic projects, AEP has equity interests in international power plants totaling 1,113 MW.
-OPCo
$50,135 47,757 31,134 Investments in power projects that are 50% or less owned are accounted for by the equity
- method and reported in Investments in Power and Distribution Projects on AEP's Consolidated Balance Sheets (see "Eastex" within the'Assets Held for Sale section of
. Note 13),' except for. Eastex Cogeneration which, due to its structure, is consolidated.
At December 31, 2002, six domestic power projects and three international power investments are accounted for under the L-85 11 -
.1 I
equity method. The six domestic projects are-
-'combined cycle gas turbines that provide stearm to a host commercial'customer and are considered either Qualifying Facilities (QFs) or Exempt Wholesale Generators (EWGs) under PURPA. The three intemational power investments are classified as Foreign Utility Companies (FUCO) under the Energy Policies Act of 1992.
Two of the international investments are power projects and the other international investment is a company which owns an interest in four additional power projects. All of the power projects accounted for under the equity method have unrelated
'third-party partners.
Seven of the above power projects have project-level financing, which is non-recourse to AEP. AEP or AEP subsidiaries have guaranteed
$58
'million of domestic partnership obligations for performance under power purchase agreements and for debt service reserves in lieu of cash deposits.
Distribution Projects AEP owns a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 AEP converted a $66 million note receivable and accrued interest
-into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and AEP's investment has been affected by the devaluation of the Brazilian Real., In' December 2002, AEP recorded an other than temporary impairment totaling $141.1 million (after federal income tax benefit of $76 million) of its 44% equity investment in Vale and its 20% equity interest in Caiua.
See "Grupo Rede Investment" within the Investment Values section of Note 13 "Asset Impairments and Investment Value Losses", for further information on the 2002 impairment of AEP's Vale and Caiua investments.
- 22. Leases:
Leases of property, plant and equipment are for periods up to 99 years and require payments of related property
- taxes, maintenance and operating costs.
The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. Capital leases for. non-regulated property are accounted'for as if the assets were owned and financed.
The components of rental costs are as follows:
L-86 i
fi I
Year Ended December 31, 2002 Lease Payments on operating Leases AMortization of capital Lease interest on apital Leases --
Total Lease Rental Costs Year Ended December 31, 2002 Lease Payments on operating Leases AMortization of Capital Leasi Interest on apital Leases Total Lease Rental osts AEP AEGCO APCO CSPCO (in thousanc
,$34,000
$76,143 '$ 6634 $ 5,209 es 65,000
~238 9,729~ 6,010
- 14. 000 19
.224Q 1.717 P
es.
-SWEPCO :TCC
.(in thousands)
I&M KPCO
~$110,833 $ 1,597
&:319 2,7
.2 221 469 TNC..
$403..
$3,240 $'7,184
$ 1,981 AEP Year Ended December 31, 2001 Lease Payments on Operating eases
$293,000 Amortization of Capital Leases
.82,000 Interest on apital Leases 22 000 Total Lease Rental Costs AEGCo.
$76,262 281 PSO SWEPCO APCO CSPCo J&M (in thousands)
$ 6,142
$7,063. $4,!
12,099
.7 2 6 171~
3ni Z7
.39 4 4 TCC TNC KPCO
-0PCO
- 74
)3 3
124 L31 A5 1,191~ $63,913 2,740
. 14,443 808 5.818 --
K4Z4 Year Ended December 31, 2001 (in thousands)
Lease Payments on operating Leases
$ 4,010 $ 2,277
$ 5948 I$ 1,534
'AMortizat-ion of capital Leases Interest on apital Leases Total Lease Rental,Costs
_AEP AEGCo AC CSPCo I&M KPCO
'OPCo Year Ended December 31, 2000 (in thousands)
Lease Payments on operating Leases
$246,000 $73,858
$ 7,128
$ 7,683 $ 81,446 $ 1,978
$51,981 Amortizat-ion of apital Leases.
118,000 281 13,900 7,776 26,341 3,931 37,280 interest on Capital Leases 36.000 55 393
~2.6 9 0 10.908
.1.054 9 584 Total-Lease Rental'Costs~
1
____4_
~TNC Year'Ended December 31, 2000
- -(in thousands)7' Lease Payments on Operating Leases 3,269. I 1,401
$ 5,410 $ 1,210 Amortization Iof capital Leas es Interest on Capital Leases____
Total Lease Rental Costs Property, plant and.equipmenit under. capital leases anrd: related obligations recorded on the Consolidated Balance Sheets are as follows-:
AEP AEGCO APo CSPCO I&M KPCO Year Ended December 3 202(in thousa:nds)
Property, Plant and Equipment Under apital.Leases Production
$ 40,000 $ 1,793 v$ 3,368
$6,380, $ 5,728 $' 1138 Distribution 15,000
.14,589 other:
Mining Assets and other.
687,Q00 6735 246791 7014 1.&I 4,258 7.
Total Property, Plant and Equipment 742,000 1,793 70,763 53,171 90,457 15,396 Accumulated Amortizatioin 299.000
-1.294 37.452 26.551 41.141 8.168 Net Property, Plant and..
Equipment under, capital Leases
$44.00 i£A9-5662
- oblig'ations under apital Leases:m Noncurrent Liability
$170,001 Liability Due within one Year 58.001 Total obligations Under capital Leases *22
$ 301 -$23,991 $21,643 $42,619
$ 5,093 198 9,9 5.967 8,229 2.155 2 S499 S3-~
S2_M 5 5D, S-?
L 87, OPo
$68,816 12,637 I,4.501 SLM5
:
I a 1.
.1 I
I w
OPCo SWEP(
Year Ended December 31, 2002 (in thousands Property, Plant.and Equipment under Capital Leases Production S2,6 Distribution S2,6 other:
mining Asets and other.
103.018 4M.
Total' Property, Plant an:d Equipment 14.7
.4 5:
. DYAcumulaed Aecmorzio 631,1 452 tosad Net Property, Plant and Equipment under Capital Leases
-o 699 699 699 Obligations under Capital Leases:
Noncurrent Liability.
.S 51,266 S
Liability Due Within One Year 14.360 Total obligations under c capital Leases S-AEP AEGCO Year Ended December 31, 2001 Property, Plant and Equipment under capital Leases
- Production
-S 39,000 S 1,983 Distribution 15,000 other:
Mining Assets and other 723.000 129 Total Property, Plant and Equipment 777,000 2,112 Accumulated Amortization 250.000 1.801 Net Property, Plant and Equipment under Capital Leases S311 obligations under capital Leases:
Noncurrent Liability
$219,000 $
76 Liability Due within one Year 75.000 235 Total obligations Under Capital Leases j4,Q0 S311 APCo CSPCo I&M (in thousands)
KPCo OPCo S 2,712 S 6,380 S 4,826 $ 1,138 14,593 82.292 85,004 38.745 54.999 61,379 26.044 86.267 105,686
- 43. 768 S4, 59 35,335 S _6,91
$33,928 $27,052 S 51,093 12.357 7.835 10.840 17.658 18,796 9.213 S 6,742 2.841 S 22,477 114.944 137,421 57.429
$ 64,261 16.405 Future minimum lease payments consisted of the following at December 31, 2002:
CaDital 2003 2004 2005 2006 2007 Later Years
..Total Future Minimum Lease Payments Less Estimated Interest Estimated Present Value Future Minimum Lease Payments
-:S 7C 53
.. 29 21
.1 5
269 Elemen 4
of AEP AEGCo APCo CSPCo I&M (in thousands) 0,000 S 249 S12,483 $ 7,365 $ 10,373 1,000 114 10,515 6,231 9,122 7000 58 6,799 5,279.
6,506 9,000 31 5,117 3,898 5,561 1,000 29 2,668 2,969 4,024 1.000 179 4,829 8.321 10.732 9,000 560 42,411 34,063 46,318 L.000 61 8.822. 6.453 (4,530)
KPCo OPCo
$ 2, 623 1,957 1,581 948 788 725 8,622 1.374
$ 17, 363
.14,634 11,442 10,220
- 8,694
- 20. 302 82,655
-17.029 5
S27,610 S
,48 S 7 S6 AEP Noncancel1able 2003
.2004
- I
-2005 2006. I 1 2007.
. Later Years Total Future Mi Lease Payment!
AEGCO operatina Leases S
305,000 73,854 271 000 73,854 252,000 73,854 242,000 73,854 237,000 73,854 2,462.000 1.107.810 i nium APCo CSPCo I&M KPCO (in thousands)
S 4,482 S 4,608 3,723 5,111 3,114 4,013 2,742 -
1,630 1,962 1,374 4.384 2.670
$ 95,213 81,246 78,968 77,741 76,461 1.117.725 OPCo
$ 1,031 'S 62,784 865 62,837 747 62,169 576
' 62,481 875.
62,880 1.492 180.548 PSO Noncancellable Oerating Leas 2003
~2004:
2005 2006 2007..
Later Years Total Future Minimum.
Lease Payments.
SWEPCo TCC (in thousands)
TNC
$ - 2,260 S 912 S 1,815
$ 448 1,998 617 1,565 296 1,714 433 1,388 192 1 391 317 1,086 169 1,256.
301 603.
167 L-88
- $3,7-00M-UM00S047 1,0 S1,2,5-S 56 S9.9
.i II
.,,~~~~~~~~~~~~~~~~
deb fr sydct of b nk
'd s cuii X
'i
'00 X
0X 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 frominvestors 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 and97%isdebtfrom pollutioncontrolbondsand expires in 2022. The Owner.Trustee owns the other bonds.
JMG was formed to design, plant and leases it to AEGCo and I&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 0-accounted for as an.operating lease with the;. f.
- 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 -: ' 0 ~. the lease or the Owner Trustee can sell the plant.
are based on JMG's cost of financing (both debt and euity andinclde anamorizaton
.AEGCo,
&M nor AEP has ownership interest in and equitY) and includte an damorizbttion.;
- the~'
compoent lus te cot of admiistraion, the Owner Trustee and do not guarantee its debt.
Neither OPCo norAEP has an ownership interest in JMG and does not guarantee JMG's debt.
- 23. Lines of Credit and Sale of Receivables:
At anytime 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 totkhet uamortzed debt andequityof.'.The AEP System uses short-term debt, primarily JMG) or sell the Gavin Scrubber. The initial 15-commercial paperand 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 forcertainsubsidiaries. Utilitymoneyparticipants
- -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.
arrangementischanged,itisreasonablypossible At December 31, 2002, AEP had $3;2 billion that AEP will consolidate JMG in the third quarter outsta'nding 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, Moody's involvement with JMG is approximately $560 InvestorServices placed AEP's Prime-2 short-million of outstanding debt and equity of JMG as :
term rating for commercial paper under review for of December 31,2002.-'-.................
-i-possible downgrade.
On January 24, 2003, Standard & Poor's Rating Services placed AEP's AEGCo and l&M entered into a sale and
..A-2 short-termrating for commercial paper under leaseback transaction in 1989 with Wilmington review for possible downgrade. On February 10, Trust Company (Owner Trustee) an unrelated.
2003, Moodys Investor Services downgraded unconsolidated trustee for Rockport Plant Unit 2 AEP's short-term rating for commercial paper to (the plant). Owner Trustee was capitalized with Prime-3fromPrime-2. Asaresult, AEP's access equity from six owner-'participants with no tothecommercial paper market will be limited and relationship to AEP or any of its subsidiaries and AEP will use other sources of funds as necessary.
The registrant -: subsidiaries jincurred interest!
transaction was entered into to allow AEP credit expense for amounts borrowed from, the AEP to repay its outstanding debt obligations, continue m
noney pooilas follows
- to purchase the AEP operating companies' Year Ended Decembe
,-....receivables,
'and accelerate its cash collections.
2002 2001 2000 AEGCo \\
- S0. (
0.8,);'$' -, -?
At December 31, 2002, the sale of receivables AEGCo
~~$0.4
$ 0.8 APCo 4.9 9.8 agreement provided the banks and commercial cSPco 3.-2 50' 1.4 I&M 4-13.1 0.8 paper. conduits would purchase a:maximum of
'0, KPCo
- ,'S-
- t.
, '.1.8
-2.3 o
$600 million of receivables from AEP Credit, of OPCo
- j:'6. 9 14.6',--
9.2 of
'so 5.4 6.3 7
which $454 ' million was' outstanding.
As SWEPCO 4.6'
- 3. 4' 4.2 collections from receivables sold occur and are TCC 11
-11.4
- 1.
olcin 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 V.:
receivables increases. All of the receivables sold subsidiaries were:
represented affiliate receivables.
The Year Ended December 31.
commitment's new term-under the sale of (inmm ions)20 20 20 receivables agreement will remain at $600 million AEGCo
,7 (in S0.1 s -
s$ -
.until May 28, 2003.
AEP Credit maintains a APCo 2.0 17-CSPCo 1.3 0 8, retained interest in the receivables sold and this I&M 2.0 1.6 9-0 interest is pledged as'collateral for the collection KPCO 0.1.
1.8
-Opco
- 0.
8 8.6 3.4
..of the receivables sold.
The fair value of the
'" ~ SWEPCo;'
~
1.6 -
.~.
0.1'
-retained interest is based on book value due to
,'TCC 2.0 0.1.
the short-term natu're 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 9 t C, i
,2002 2001 through purchase agreements with affiliated Balance outstanding:..
companiesand,untilthefirstquarterof2002,with Notes Payable
'$1747
$1063 non-affiliated companies.- As a result of the commercial paper IA117
'2 948 Total p '
- restructuring of electric utilities in the State of Texas, the purchase agreement between AEP Sale of Receivables - AEP Credit x U :; Credit-and Reliant Energy, Incorporated was
% 9>
i
't'
~
'S
' tS '~r
~'~ '
terminated as-of January 25,-;002
-nd the AEP Credit ent'er'ed into a sale.of receivables temnedaofJury2,02adth purchase agreement between AEP: Credit and agreement with a group of banks and commercial Texas-New Mexico Power Company, the last V : '
paper conduits. Under the sale of receivables :.
remaining non-affiliated company, was terminated agreement, which expires May,28,.2003, AEP on February 7, 2002. In addition, the purchase Credit sells an' interest in the. receivables it agreements between AEP Credit and its Texas acquires to the cormmercial paper conduits and affiliates AEP TexasCentral Company (formerly banks'.and receives cash.
This transaction constitutes a sale of -receivables in accordance Cenal Pora Company and eP withSEA 140allwingtherecevabes t be Texas'.North Company (formerly West Texas
~with SFAS.140 allowing the receiv able6s to be
- 'ujiis"opn)were triae fetv Utilities'Copn)wr
'terminated effective taken off of AEP Credit's balance sheet and Ma 20 2002.
allowing AEP Credit to repay any debt obligations.
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 J-
Comparative accounts receivable information for AEP Credit:
~Year Ended'December.31, proceeds
~~~~2002 2001~
from sale of (in millions)
Accounts Receivable
$5,513
$1I,134 ACcountS Receivable ReandInterest Less uncollectible Aounts and Aounts Pledged as collateral 76 143 Deferred Revenue from servicing Accounts Receivable15 Loss on ale of Accounts, Receivable~
48 Average variable Discount Rate 19%2.28%
Retained Interest if.10%
Adverse change in uncollectible Accounts 74142 Retained Interest if 20%
Adverse change in uncollectible Aounts 72 140 Historical loss and delinquency amount for the portfolio:
AEP. System's Customer ACcountS Receivable Retained MiscellaneouS ACCOuntS Receivable Retained Allowance for uncollectible AountS Retained Total Net Balance Sheet'ACCountS Receivable Customer Accounts Receivable securitized.(Affiliate)
Customer ACcountS Receivable securitized (Non-Affiliate)
Total AcountS Receivable managed Net uncollIecti bl eAccounts Written,Off customer accounts receivable managed Face Val ue Year Ended December 31, 2002 2001 7(in mil i ons)-
$466
$ 343 1,394 1,365 (119)
(69) 1,741 1,639 454 560
~~485 48 72 L-91 I
I I w -
I ;.
- t: ;.
I a
Customer accounts receivable retained and securitized for the domestic electric operating.
companies are managed by AEP Credit.
Miscellaneous account receivable have been fully retained and not securitized.
At December 31, 2002, delinquent customer accounts receivable was $30, million.
Under the factoring arrangement certain of the registrant subsidiaries (excluding AEGCo) sell without recourse certain of their customer 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
( nmi 11 i ons)
APCo S 67.6 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 The fees paid by the registrant subsidiaries to E AEP Credit for factoring customer accounts receivable were:
APCo CSPCo I&M KPCo OPCo.
PSO SWEPCo TCC TNC Year Ended December 31.
2002 2001 2000 (in mEH-lions)
$ 4.8 S 5.2 -
S -
15.8 15.2 10.8 7.4 8.5 6.8 2.7 2.7 1.9 11.4 12.8 8.4 7.2 9.6 8.3 5.4 7.4 9.2 2.2 14.7
- 15.7 1.4 3.8 4.0 L-92 i.
- 24. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows:
2002 Quarterly Periods Ended
(
d: 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 (0.53) 0 12 (2.47)
Share**
'(0.53) 0.19 1.25-(2.47)
(In Millions -' Except
'Per hare Amounts)
March Revenues
$2,910 operating Income
- 521 Income Before Discontinued operations,
-Extraordinary Items and cumulative Effect:
-- 230 Net Income... :
266 Earnings per Share Before, Discontinued operations, Extraordinary Items t.
and cumulative Effect***
0.72:
Earnings'per share****
0.83 zuui Quarteriv 31-June 30 X $3,259 622
-- 251
- 232
- - 0.77
-0.72 Perioas Enaea Sept. 30
$3,733 -
-.-824 399 421
- i 1.23
- I -1.31-
- 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 $3.01 earnings per share due to rounding.
The unaudited quarterly financial information for each AEP registrant subsidiary follows:
R f
0 :. f
' --.. :;. 0 -.'$S,, -D f :'
t
)
0 t
- 0 X
' " ' ' '. ' "' ' D.' '
. ' 0,' X,;
' ';' ' 0. ' ;.
A
¢ t
'}
0 ' '
' ' 0 ' ' ' ' ' "
S
- i ' '
i
'+04,
'-s' X,
'1.'0feS-+'S 8', wEt0*'
- l2"
. '0 ','
'0' 000; 0: - '0\\ 0 04 0 L-93 ' j' Dec. 31
$2,865 215 37 52
- 0.12 0.16
.i I
I I I
- . I
j I
I I
- 1:1 s
Quarterly Periods Ended AEGCo AP 2002 March 31 operating Revenues
$49,875
$462 Operating Income 1,767 81 Income Before Extraordinary Items 1,893 55 Net Income 1,893 55 June 30 Operating Revenues
$53,356 $432 operating Income 1,504 65 Income Before Extraordinary Items 1,718 46 Net Income 1,718 46 September 30 o operating Revenues
$55,988
$474 operating Income 1,436 81 Income Before Extraordinary Items 1,947 53 Net Income 1,947 53 December 31 operating Revenues
$54,062
$445 operating Income 1,422 73 Income (Loss) Before Extraordinary Items 1,994 49 Net Income (Loss) 1,994 49 Quarterly Periods Ended OPCo P
2002 March 31 Operating Revenues
$520,652
$148 operating Income 83,716 8
Income (Loss). Before Extraordinary Items 64,051 (1
Net Income (Loss) v 64,051 (1
June 30 Operating Revenues
$521,365
$158 operating Income 61,046 20 Income Before Extraordinary Items 55,348 11 Net Income 55,348 11 seotember 30 operating Revenues
$566,366
$230 Operating Income (Loss) 97,210 50 Income (Loss)
Before Extraordinary Items 80,258 41 Net Income (Loss) 80,258.
41 December 31 Operating Revenues.
$504,742.. $256 operating Income (Loss) 56,357 5
Income (Loss) Before Extraordinary Items 20,366 (9
Net Income (Loss) 20,366 (9
Quarterly Periods Ended AEGCo AP
- 2001 operating Revenues
$50S operating Income 1,807
.88 Income Before Extaordinary Items 1,980 61 Net Income 1,980 61 June 30 operating Revenues
$52,217
$430 Operating.Income
- 1,882 59 Income Before Extrodinary Items i
2,063 36 Net Income 2,063 36 SeDtember 30 operating Revenues
$57,417
$434 Operating Income 1,615 60 Income Before Extraordinary Items 2,051 30 Net Income 2,051 30 December 31 operating Revenues.
$57,407
$418 Operating Income 1,673 67 Income (Loss) Before Extraordinary Items 1,781 33
- Net Income, (Loss) 1,781 33 L-94 Co
(
,605 1554
,341
,341 015
,224
,608
,608
,282
,365
,947
,947
,568
,920
,596
,596 SO.
,986
,410 1,648)
,648)
,330
,201
,620
,620
,098
,710 1,002 1,002
,233
,400
,914)
,914)
Co
.,204 8,152 1,787
.,787 0,412
, 362 6,419 6,419 4,450 1, 381 0 317 1,317 8,193 7,091 3,295
,295 ICSPCo in tousand 1:.
$314, 826
$7 45, 548 33,858 33,858
$343, 813
$1 58, 040 51,721 51, 721
$428,437
$1 89,033 76,117 76,117
$313,084 27,158 19,477 19,477 SWEPCo (in thouisands)
$222,259 s:
22,469 8,159 8,159
$263,074 31,988 18,155 18,155
$362,423 60,254 45,794 45,794
$236,964 V
27,758 10,884 10,884 CSPCo (in thousands)
$327,437
$7 51,932 37,671 37,671
$333,995 62,894 47,418 21,011
- $375,691
$7 76, 920 65,318 65,318
$313,196 60,431 41,493 37,876 I&M 352,235 30,363 11,058 11,058 369,043 19,865 7,494 7,494 121,472 57,004 35, 312 35,312 384,014 43,957 20,128 20,128 TCC
- 78,910 55,445 24 445 24,445 360,391 64,319 33, 535 33, 535 546,260 118,204 93,383 93,383 304, 932 155, 765 124,578 L24, 578 I&M 387,813 52,698 32,363 32,363 382,234 47, 340 27, 374 27,374 398,457 44, 509 25,064 25,064 358, 493 15,158 (9,013)
(9,013)
KPCo S 99,185 15,484 10,246 10,246 S 92,164 9,550 5,246 5,246
$100, 359 11,119 5,994 5,994
$ 86,975
- 6,044 (919)
(919)
TNC
$103,626 11, 145 3,992 3,992
$104,452 5,547 675 675
$152,667 (308)
(4,193)
- (4,193)
$ 89,995 (8,513)
(14,151)
(14,151)
KPCo
$100,681 12,604 7,075 7,075
$ 89,541 8,364 2,742 2,742
$ 96,197 12, 587 5,
312 5,
312
$ 92,606 14,123 6,436 6,436 is),
Quarterl eri odS' Ended OPCo P0SWEPCo.
TCC TNC (in thousan ds) 2001
.March 31
/
operating Revenues-
$552,503 $2500
$267,117
$432,910
$141,(649 operating Income,.
-6,5:
8340 33,986 64,152
.5,392 income Ls)Bfr xrordinary,Items 53,397, (1,560)
-19,869 35,03189 Net.Income.(LOSS)
Z 53,397 (1,560) 19,869
-35,031 891 June 30 operating Revenues
$52196 $265,360
$271,4
$4040 $139,228 operating Income...
4707 21,942 32,649 82,351 12,428 income Before Etraordinary'Itm
.32,094.
11,921'
.17,784 52,518 6,133 Net Income
~IIems10,579 11,921:
- 17,784
- 52,518 6,133 sentember 30 operating Revenues'
.$535,535.$325,373
$3 31,441 52 7,117
$181,433 operating Income
.69,668 59914... 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 operatinglRevenues
$9,7
$1,87 231,020
$308,390
$ 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)`:
320 91.
- (3,671)7 5,357 11,027 (8,781 ncom Befre Dicontiued Operations, Extrardinary Items and Cumulative Effect for thefut quarter 2002 de'crea"sed $896 million from the prioreyear due to the impairment loss and impairment valuelosssof pproimatly $,188million (re-tax) to reduce tevlation of under-performing assets. In addition to the impairments that were recorded during the fourth quarter, a ch'ange 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.
2.Tut Preferred Securities:
The fllowng Trust Preferred Securities issued by the wholly-ownedsauoybinstrtsf PSO, SWEPCo and TCC were outstanding at December 31, 2002 and Decemb'er 31, 2001. They
.ar classified on AEP's, PSO's, SWEPCo's d TCC`s BlneS etasCrin ubdary Obligated, Mandatorily Redeem able Preferred Securities of SubsidiaryTrusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. TCC reacquired 490,000 trust preferred units during'2001.
sueit d/-
Description of
-Outstanding
?
underlying.
BUsiness Trust security At 12/31/0 DAonta ecember 31.
Debentures of Registrant 2O025 (i millions)
CPC.Capital I 8.00%,-SeriesA 5,450,000_
$136
$136 TCC, $141 million, 8.00%,~ serieS A PSO Capital I
-8.00%, SerieS A~
3,000,000;
~
75 75 Pso,:$77 million,
~~~~~~~~~~~~~~~8.00%,.se A
SWEPC Captal 7.85%; Seie
`A-4,400.000 110 310 SWEPCO, $113 million,
. ~7.875%, serieS A Each of the business trusts is treated as a subsidiary of its parent company. The only assets of.the business trusts are the subordinated debe'ntures issued by their parent company asspecified above. In addition to the obligations under their subordinated debentures, each of the parent' compaies hs als 'ageed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.
26.' Minority Interest in Finance Subsidiary:
In ugut 201,AEP fomed AEP Energ Srices Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis).:' SubOne is"a wholly,.owned consolidated subsidiary of AEP that was L
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 un6onditional obligation to fund $83 million from SubOne and $750 million from Steelhead lnvestors 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.
Under the 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 in AEP 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 agreenent 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 agreenent or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an 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 in the 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 identityfrom 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, $83 million underthe subscription agreement to Caddis for any losses incurred by
-- Caddis and the cash reserve fund balance of $34 million (as of December 31, 2002) due Caddis for L-96 l
v
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 per equity unit is $50. The number of shares to 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 p'urchase 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.
C,
I..
1, : -
- I
- 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'he 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:
~ 1 uuL
.11.
Companv's share I --
December 31.
Percent Utility
.Construction of Plant work
-ownership in Service in Pro ress (ln ttlhousands)
CSPCo:
W.C. Beckjord Generating station (Unit No. 6) 12.5 -S 15,487 -
49 Conesville Generating Station (unit No. 4) 43.5 81,960 279 J.M. Stuart Generating Station 26.0 197,276 44,865 Wm. H. Zimmer Generating Station. 25.4 705,620-14,077 Transmission Ca) 61.187 2 281 P50:~~~~~~~_
PSO:
-. I oklaunion Generating Station (Unit No. 1) 15.6 SWEPCo:
Dolet Hills Generating Station (Unit No. 1) 40.2 Flint Creek Generating Station (Unit No. 1) 50.0 Pirkey Generating station (unit No. 1) 85.9 TCC:
oklaunion Generating Station (Unit No. 1) 7.8 South Texas Project Generating S station (Units No.-1 and 2) 25.2 TNC:
oklaunion Generating station (Unit No. 1) 54.7 (a) varying percentages of ownership.
23,62 1313 w :. :
- 0..
S 235,366 1,313:
91,567 1,052 451.136 2.197
$ 778.069 S 4,562 38,055
$-- 369 2-364 359 43 887 2001 Utility Construction Plant Work in service in Proqress (in thousands) 14,292 884 81,697 494 193,760 27,758 704,951 2,634 61 476 91 82,646
$634
$ 234,747 S
675 83,953 213 439.430 10.577 S
37,728 318 2.360.452 41.571 The accumulated depreciation with respect to each AEP registrant subsidiary's share of jointly owned facilities is shown below:
December 31, 2002 2001 (in thousands)
-$436,683_
$410,756 49,085 35,653 450,057 392,728
- 927,193 863,130 102,542 100,430
. 29. Related Party Transactions Power Pool APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6,
- 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in. relation to the sum of the maximum peak demands of all five companies during the preceeding 12 months.
In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the
- SWEPCo TCC TNC AEP System 11 -
- . I s
i,.
q -,
- 1 1.
. t..
S-L-M
- 9
transfer ofS02 Allowances associated wih dtda f Janay1,97(WOprtn transactions. under the*~ Interconnection Areement). The CSW Operating Agreement Agreement.. As part of AEP's restructuring requires the operating opne of the west settlement agreement filed with FERCI under zone to maintain sp'ecified annual plan6ing certain conditions CSPCo and OPCo Would reserve margins and requires, the operating no longer be parties to the Interconnection' cmaiesthathave capacity in excess of the Agreement and. certain other moiiaino rqired margins~ to make such capacity,
.. ~its terms would also be made..
available for sale to other, operating companies as capacity commitments. The Powe mreigadtading transactions
_CSW Operating Agreement also delegates to (trading activities) are conducteadby 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 activitiesivolve the! purchase' and, generating units and to' supervise the sale, of. electricity under%physical' forward operation and maintenance of a central contr acts at fixed and variable prices and the
-control center. As part of AEP's restructuring trading of electricity contracts iuig stlmn gemn ie ihthe 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 Systemn Integration Agreement typically settled by enterinig into-offsetting-poide for the integration and coordination contracts.
b f 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 an'd 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 LAEP System's traditional
.as an umbrella agreement in addition to the marketing area.
AEP: Interconnection Agreement and the
.CSWLOperating Agreement, each of which PSO, SWEPCo, TCC, TNC and AEP Service will continue to control the distribution of costs Corporation are partieSr to: a Restated anhd and benefits within each zone.
Amended Operating Agreement.originally,.
L-99 1 7.
- I
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 $ 197.525 $ 22.369 S397.24R $
Saies to West system Pool w-18,300- 12,107 Direct Sales To East Affiliates. 58,213 Direct Sales To West'Affiliates '
other 3.313 2 109 Total Revenues -
1 2001 sales to East system Pool;
$ 91,977 $44,185 sales to West System Pool 24,892 13,971 Direct sales To East Affiliates 54,777 Direct Sales To West Affiliates (3,133) (1,705) other 2.772 11.060 Total Revenues,:,
2000 Sales to East System Pool' Sales to West System Pool..
Direct.Sales To East Affiliate!
Direct Sales To West Affiliates other Total Revenues.'
Related Party Revenues 2002 sales to East System Pool sales to West System Pool Direct SaleS To EaSt Affiliate!
Direct sales To west Affiliates other Total Revenues 13,036 4,717 16,265 I
50,599 3.577 878 1 090
$214138
$2 S4
$-239,277 $ 34,735
--15,596 6,117 (1,905)
(744) 2.071 2.258 L 25,0 S4 S 81,013 $36,884 S 200,474 7,697.
4,095
-,4,614
- 59,106 4,092' 2,262 -
- 2,510 2.770 6.124 2.710 PSO SWEPCo TCC (in thousands) 213,071
$21,07
$431,637 19,797 55,450 227,338 (2,590) 7.072
$511M 26 22,3 S 36,554 $502,140-$
1,829 6,356 66,487 227,983 972 3,421 2 466 4.043 TNC
.s - -
s 674 1,334 18,416 1,280 611.
270 -
366 -
(23) s 6,047 75,674 956,751 228,404 2.107 (4.979) 32 91 10.764 5~~~~i&
9,3 7,9 10R44&4J2 2001 Sales to EastSystem Poo:
4$
S 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 52583 7
5 58 Total Revenues 2000 Sales to East System Pool' sales to'west System Pool
- i 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 9
(12.680)
- 2) 5 163 11.931 Total Revenues 1,48$312 7;s
=
5 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:
Related Party Purchases 2002 Purchases from East system Pool Purchases from West System Pool Direct Purchases from East Affiliates Direct Purchases from West Affiliates Total Purchases 2001 Purchases from East System Pool Purchases from west system Pool Direct Purchases from East Affiliates Direct Purchases from west Affiliates Total Purchases, 2000 Purchases from East System Purchases from west system Direct Purchases froM East Direct Purchases from west Total Purchases APCo CSPCo I&M KPCo (in thousands)
$233,677 $309,999 $ 83,918- $ 68,846 337 219 237 86 583 387 149,569 64,070 34,582 $292,04 S346,582 $292,034 296 165 Pool
$355,305 S287,482 Pool 455 260 Affiliates Affiliates 14 8
S3s74S2815 S 79,030 185 159,022
$ 61,816 72 68,316
$10,0
$106,644 $ 58,150 285 108 158,537 69,446 9
3
-L-100 oPCo
$70,338 297 519
$62,350 235 S50,339 390 12 I
1 1
- 1I I!
- ~
I I
I X
I
.i
SWEPCO' TCC
.. TNC
.Related Party Purchass..-
C thousands).
2002 Purchases from:Ea-st Sys tem PoIol 343 Purchases from'west system Pool
-874
-. (456)
J, 3
- 66. 15,475
~Direct Purchases froM East Affiliates -'29,029 17,242 8,236' 2,669
-Direct urchases from west Affiliates 59.208~ 25.236-1384 19.438
- Total Purchases
.~
,L' 2001 Purchases froM East system Pool
$1,32
- 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 A4,614
- Di rect Purchases from west Affiliates 34.603 ~9.696 ~45.569 40 349 Total Purchases 200 Purchases from East system Pool 1$20 100$--
Purchases from west system Pool*
5,386 4,379 1,696. 18,444 Direct urchases-froM East Affiliates
-2,117 695-251.
71'.
Direct Purchases from WeSt Affiliate 33 185 8 264.
04 3 5 Total Purchases The above summarized related party revenues and expenses are, reported in their entirety, without elimination, adre presented as operating revenues affiliated and purchasedpoeafiatdn the'statements~ of operations of each AEP Power,Pool member.I.Since.all,of the above pool mfembers are included in AEP's cnsolidated results, the aoesm aie eae at transactions are'eliminated in total in AEP's consolidated revenues and expenses.
L-1O1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
AEP System Transmission Poc APCo, CSPCo, I&M, KPCo al parties to the Transmission Agn April 1, 1984, as amended (the Agreement), defining how th costs associated with their relat of the extra-high-voltage transrr (facilities rated 345 kv and abov facilities operated at lower voll and above).
Like the In Agreement, this sharing is bas company's "member-load-ratio.
The following table shows the r charges allocated among the Transmission Agreement dur ended December 31, 2002, 201 2002 2001 (in thousan APCo CSPCo I&M KPCo OPCo
$(13,400) 42,200 (36,100)
(5,400) 12,700 S (3,100) 40,200 (41,300)
(4,600) 8,800 Transmission Agreement during the years ended December 31, 2002, 2001 and 2000:
nd OPCo' are
'e m ent,dated
. ;0
-. ~- -l 2002 2001 2000 Transmission thousands) sy h the PSO
$(4,200) 5 (4,000)
$ (3,300) ey share the SWEPCo (5.000)
(5,400)
(5,900) iveownership, TCC 3,600 3,900 3,400 TNC 5,600 5,500 5,800 iissioh system Pe) and ertain --
'e and certain AEP's System Transmission Integration tages (138 kv Agreement provides for the integration and terconnection coordination of the planning, operation and ed upon each E'maintenance of the transmission facilities of AEP's' east' and west zone operating subsidiaries.
Like the System Integration (credits) or Agreement, the System Transmission
.parties to the Integration Agreement functions as an ng the years umbrella agreement in addition to the AEP 01 and 2000: -
Transmission
'Agreement and the
-; 2000 Transmission Coordination Agreement. The ds)
System Transmission Integration Agreement
$ (3,400) contains two service schedules that govern:
38,300 (43,800)
(6,000) 14,900 PSO, SWEPCo, TCC, TNC and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1,1997 (TCA). The TCA established a coordinating committee, which is charged' with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff.
Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf.
The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT.
The following table shows the net (credits) or charges allocated among the parties to the L-102 The allocation of transmission costs and revenues.
The allocation of third-party transmission costs and revenues and System dispatch costs.
The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.
Unit PowerAgreements and Other A unit power agreement between AEGCo and l&M (the l&M Power Agreement) provides for the sale by AEGCo to l&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by l&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%.
The l&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances.
I.
.A I
. i i
7 7 -
.I
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/o professional services to AEP,,System of the power (and the energy associated' companies. The osts 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 forthe 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 'i&M Power Agreement 'for. such use of equity capital, which is furnished to entitlement. The'KPCo unit power'agreement'-
AEPSC by AEP Co., Inc. Billings from AEPSC expires on December 31, 2004. This unit are capitalized or expensed depending on the power agreement extends until December31, nature of the services rendered. AEPSC and 2009 for Unit'l and until December 7, 2022 its billings'are subject to th'e regulation of the for Unit 2 if AEP's restructuring settlement
'SEC underthe 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 thesefacilities 2003, AEP priced its offering of 50 million are apportioned between the owners based L:shares of common stock at a public offering on ownership' interests; Each company's 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,N Senior Notes 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 mi ons) 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 management's discussion and analysis of financial condition, accounting policies and other matters for AEP. and its, registrant subsidiaries. Management's, discussion and analysis of results of operations for AEP and each of its subsidiary registrants is presented with their financial statements earlier in this document. The following is a list of sections of management's discussion and analysis of financial condition, accounting policies and other matters and the registrant to which they apply:
Financial condition critical Accounting Policies Market Risks Industry Restructuring Litigation Environmental Concerns and Issues other Matters AEP, AEGCo, APCo,
- CSPCo, I&M,
- KPCo, OPCo,
- CSPCo, I&M,
- KPCo, OPCO, PSO, SWEPCo, TCC, TNC AEP, APCo, CSPCo I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC AEP, AEGCo, APCo, CSPCo,.I&M, KPCo,
,OPco,
- OPCo, PSO, SWEPCo, TCC, TNC Financial Condition We measure our financial condition by the strength of the balance sheets and the liquidity provided by cash flows and earnings.
Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality.
Credit Ratings The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries.- The agencies are also reviewing most companies in the energy sector due to issues which impact the entire industry, not
.only AEP and its subsidiaries.
In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its. rated subsidiaries.
The results of that review were downgrades of the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baal to Baa2, TCC from Baal to Baa2,: PSO from A2 to Baal, SWEPCo from A2 to Baal. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was, also concurrently downgraded from P-2 to P-3. The completion of this review was a culmination of earlier
.ratings action in 2002 that had included a downgrade of AEP from Baal to Baa2 and, the placement of five of the. registrant subsidiaries on negative outlook. With the completion of the reviews, Moody's has placed AEP-and its rated subsidiaries on stable outlook.
In February 2003, Standard & Poor's placed AEP's senior unsecured debt and commercial paper ratings on credit watch with negative implications, and did the-same with the subsidiaries. S&P indicated that resolution regarding these actions would come within a short time, (see additional discussion in Financing - Credit Ratings in Item 1 of Part I).
In 2002, Fitch. Ratings Service downgraded both PSO and SWEPCo from A to A-for the senior unsecured notes. Fitch has AEP and its subsidiaries on stable outlook and the commercial paper rating is stable at F-2 (see additional discussion in Financing -
Credit Ratings in Item 1 of Part I).
Current ratings of AEP's subsidiaries' first Liquiditv mortgage bonds are listed in the: following table:
Liquidity, or:accessto cash, has become a-,-
C-a Moody's SP F -,
i'-
more critical factor in determining the financial -
comi2anv
-,y Moody's. 'S&P:'.
Fitch j
stability of a company due to volatility in APCo tBaal0 BBB+-'
A-.;,
' hwholesale' power markets and the potential CSPCo A3 ABBB+
A--.a,e.p,we.m I&M
- Baal
.'BBB+
BBB+
limitations that'credit rating downgrades place KPCo Baal.
BBB+-.
BBB+
OPCo
, :-0.
.. 0,,.
A3aal:.-
,BBBB+ ;.ABB+,,
on. a company's ability to raise,capital.
PSO A3 BBB+
A Management is committed to preserving an SWEPCO A3.'
BBB+, ~A TCC
,,,Baal BBB+
A adequate liquidity position and addressing TNC
~~~~aa].
BBB+~, At TNC - - ' ;
A3, BBB+:,-Af
.,s' -
AEP and its subsidiaries' financial needs in 2003.
Currentshort-term ratin'gs are as follows:
0T-Compan -'
v;.
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 Facilities.
are listed in the following table: -(n millions) MaturitY Comany Moody'
's -'
Fitch
'-,'commercial Paper Backup CompanY a
B Lines of Credit
$2,500*
5/03 commercial Paper Backup
-AEP Baa3 ^:-BBB+-
BBB+:
- Lines of credit 1,000 5/05
- AEP Resources*
Ba3 BBB+
BBB+
.croaesprto Aes*
Baa3 2 BBB+ Z BBB+;-.
Revolving credit 1,725 CSPCo
,A3
- i. BBB+
A-
'Euro Revolving credit, I&M Baa2
.BBB+
BBB 1Facilities 315
.0/03
~KPCo Baa2.
BBB+
BBB otal 5,540 OPCo A3 BBB+
-::BBB+
PS0
-Baal BBB+.
A-cash SWEPCO Baal BBB+
A-U
- Liquidity Reserve 1.000**
TCC-Baa2 BBB+-
A-
- Total credit Facilities TNC Baa].
_B+
-and ash
-6,540, The rating is for a series of senior notes issued with a Support
-Agreement from AEP.
Less: Comaercial Paper
'.-.:- -outstanding Corporate Separation 1 415 Loans 1, 300 AEP's common equity to total capitalization:
Euro Revolving
% i 20010
'~'
credit Loans 305' declined to 32% in 2002 from 36% in 2001 Total drdiioas y
0 and 37% in 2000.
Total capitalization includes long-term debt due within one year, U*
Contans one yar -erut provision.
unrestricted and excludes $213 million equity unit senior notes, minority interest and.'-
. of operational cash on hand.
short-term debt.
Preferred stock at 1%
remained unchanged. ln 2002, long-term debt.
including equity unit senior notes and trust ' 0 0 0 AEP and its subsidiaries' goal for 2003 is to preferred securities increasedfrom 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 remnained unchanged at'3%. In
- as an interim bridge for timing differences in 2001 Long-term Debt remained uchanged' t
n 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 lnterestr in Finance Subsidiary increased to 3%. In 2002,2001
'Short-term funding comes from the parent
- f -: -: :- ' and 2000, AEP did not issue any shares of company's commercial! paper program and
- ' ' - -t common stock to meet the' requirements of ' t 0.--
revolving credit facilities.
Proceeds are the Dividend Reinvestment and Direct Stock loaned to the subsidiaries through Purchase Plan and the 'Employee Savings intercompanynotes-AEP and itssubsidiaries
. ' 0 -
..- '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 external
' '. :' offering (discussed ini Financing Activity).
:short-term funding requirements and sell 4:
- ; :;.-:--accounts receivable to provide liquidityforthe domestic electric :subsidiaries.
The M
commercial paper program is backed by $3.5 billion in bank facilities of'which $1 billion matures in May 2005. The remaining $2.5 billion matures in' May 2003 and has a one-
,year term-out provision'at AEP's option. At December 31, 2002, 'approximately $1.4 billion of commercial paper was outstanding.
A portion of the commercial paper balance is related to funding of debt maturities of the Ohio and Texas' subsidiaries pending a permanent financing'program. The Ohio and Texas subsidiaries issued $2,025 million of senior unsecured notes in February2003with maturity dates ranging from 2005 to 2033.
The commercial paper balance outstanding decreased in early 2003 due to repayment with proceeds from these issuances.
AEP also has a $1.725 billion bank facility maturing in April 2003 that is available for debt refinancing. At December31,2002, $1.3 billion was outstanding under that facility.
With the issuance of the permanent financing for the Ohio and Texas subsidiaries mentioned above, this facilitywas repaid and cancelled in February 2003.
AEP also has revolving credit facilities in place for 300 million Euros to support the wholesale business in Europe. At December 31, 2002, the majority of these facilities were drawn.
AEP also maintains a minimum $300 million cash liquidity reserve fund to support its marketing operations in the U.S. and keeps additional cash on hand as market conditions change. At December 31,2002, AEP had $1 billion of cash available for liquidity.
On December 6,2002, we closed a 364-day,
$425 million facility and used it to partially repay'the maturing interim financing for the U.K. generation plants (FFF). The facilitywas secured by a pledge of the shares of AEP companies in the FFF ownership chain and guaranteed by the parent company. A portion
'($213 million) of the facility is:due in May 2003.
The remainder of the FFF interim financing was repaid using a combination of existing funds and draws against the Euro
'revolving credit facilities.
In total, we had approximately $6.5 billion in liquidity sources'of which $3.5 billion were
.;'unused and available at December 31, 2002.
During 2002, cash'flow from operations was
$1.7 billion, including $21 million from Net Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect, approximately $1.3 billion from depreciation, amortization, deferred taxes, and deferred investment tax credits, approximately $1.1 billion associated with asset, investment value and other impairments, offset by additional working capital requirements of approximately
$700 million. These additional working capital requirements reflect the one time impact of the discontinuance of the sale of accounts receivable for Texas companies and billing delays related to the transition to customer choice in Texas, higher margin requirements for gas trading, seasonal fuel inventory growth, and other miscellaneous items.
Construction expenditures were $1.7 billion including major expenditures for emission control technology on several coal-fired generating units (see discussion in' Note 9).
Dividends on common stock were $793 million. Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the Texas REPs and the issuance of common stock, common equity units, 15-year notes for a wind generation project and transition funding bonds provided funds to reduce debt, fund construction and pay dividends.
During 2001,'AEP's cash flowfrom operations was $2.8 billion, including $885 milion from Net Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect and
$1.4 billion from depreciation, amortization, deferred taxes and deferred investment tax credits. Capital expenditures including acquisitions were $3.9 billion and dividends on common stock were $773 million. Cash from operations less dividends on common stock financed 51% of'capital expenditures.
During 2001, the proceeds of AEP's $1.25 billion global notes issuance and proceeds from the sale of a U.K. distribution company and two'generating plants provided cash to purchase, assets, fund construction, retire debt and pay dividends. Major construction expenditures include amounts for a wind generating facility and emission control technology on several coal-fired generating M-3
units. Asset purchases includeHPL, Icoal 'be immediately payable.
mines, a barge line, a wind generatin faiiy
.-and two coal-fired generating plants in the Financin Activity 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
-n 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 Eamings for 2001' resulted in. a dividend' cash liquidity reserve fund.'
payout-ratio' of 80%,
- a. considerable improvement over th'e 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 by the 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 creditfacilityand a $600 million 364-ments.
The domestic. electric subsidiaries'-i day term loan facility to prepare for corporate generally issue short-term debt to provide for separation.- At year-end, $600 million was interimfinancing 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 rmillion 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 4-
due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%.
The use of proceeds from the above bonds was repayment of the bridge loan facility mentioned above, repayment of short-term debt, and for general corporate purposes.
In 2002, the following issuances 'were
' completed by the subsidiaries of AEP:
Prin-ci pal Amount (in Com-Type of mil-Interest Due pany Debt lions)
Rate Date senior APCo unsecured
$450 4.80%
2005 Notes L_:_._.
Senior APCo unsecured 200 4.32%*
2007 Notes Installment I&M Purchase S0 4.90%
2025 Contracts Senior 12 I&M unsecured 10 6.0%
2032 Notes Senior KPCo unsecured 100 6 3/8%
2012 Notes senior KPCo unsecured 125 5.50%
2007 Notes Senior KPCo unsecured 80 4.32%*
2007 Notes senior KPCo unsecured 70 4.37%*
2007 Notes Senior PSO Unsecured 200 6.00%
2032 Notes senior SWEPCo.
Unsecured 200 4.50%
2005 Notes Other Notes 121 subsid-Payable 6.60%
iaries '
other Revolving 305 variable 2003 S;ubsid-credit iaries credit
- Interest rate payable by subsi iary in U.S.
dollars.
while these companies do not have Australian rate obligation, there is an underlying interest rate to Australian investors in Australian dollars of either 6%
or a variable rate.
7'The subsidiaries also redeemed approximately $2 billion of long-term 'debt in 2002. See the Schedule of Long-term Debt for' each registrant in sections B to' K for.
details.
s.
'AEP uses money pools to meet the short-term borrowings for the majority of its subsidiaries
- ln'addition,'AEP also funds the short-term
'debt requirements of other subsidiaries that are not included in the money pool. As of an December 31, 2002, AEP had credit facilities totaling $3.5 billion to support its commercial paper program. At December,31, 20p2, AEP had $1.4 billionli outstanding in short-term borrowings subject to these credit facilities..
AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies.
AEP Credit's financing for, the purchase of receivables changed in..' December 2001.
Starting December 31, 2001, AEP Credit entered into a sale of receivables agreement.'
The agreement allows AEP Credit to sell certain receivables and receive cash meeting the requirements of SFAS 140 for the receivables to ' be removed from AEP's - and the subsidiaries' Balance Sheets.' At December 31, 2002, AEP Credit had $454 million sold under this agreement. See Note 23 for further discussion.
Off-balance Sheet and Minority Interest Arrangements.
AEP and its subsidiaries enterinto off-balance sheet arrangements -for variou's reasons ranging from accelerating cash 'collections, reducing operational expense to spreading risk of loss to third parties.
The following identifies significant off-balance
'sheet arrangements:
Power Generation Facility AEP has entered into agreements with Katco Funding L.P.
(Katco),
an unrelated unconsolidated special purpose entity. Katco has an aggregate financing commitment of
$525 million and a capital structure 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.
Katco was formed to develop, construct, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease will be accounted for as an operating lease (see Note 22), therefore neither the facility nor the related obligations are reported on AEP's Consolidated Balance Sheets. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW), which will M-5 i'."
use the energy produced by the facility and increase. Annualpayments of approximately sell excess energy. AEP has agreed to'
-$12 million'represent future minimum purchase the excess energy from DOW for
'payents, 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 ofits 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 tern 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 Subsidiary investors of Katco. 'At the end of each lease term, AEP may renew the lease atfairmarket
.n 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 project's 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 5("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 underthisoperating lease will also relationship to AEP or any of its subsidiaries and 97% is debt from a'syndicate of banks.
- -.- :'.. 0.- - ;--. ' ' -'
- - ;M -6.
The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company.
Under the 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 in AEP 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 is an 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'X provisions of applicable agreements..
Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain 'events including a default in the payment of the preferred return, Steelhead's rights include: fdrcing 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 income statement and balance sheet 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, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of $34 million (as of December 31, 2002) due Caddis for 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, management is continuing to review the application of FIN 46 as it relates to the Steelhead transaction.
AEP Credit AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits. Under the sale of receivables agreement, which expires May 28, 2003, AEP Credit sells an interest in the receivables it acquires to the commercial paperconduits'and banks and receives cash.
This transaction constitutes a sale of 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 has7an 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 optionto 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 allowAEP Credittorepayits 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
-:oeratngreceivables,"
and
'-,non-cancelable. At the end of the initial term, operating companies' r
OPCo can renew the lease, purchase'the accelerate its cash collections.
GvnSrbe trspeiul etoe)
At December '31, 2002,' the'- sale of '<
tor sell the Gavin Scrubber. In case of a sale receivables agreement provided the bank s
- at' less than the adjusted acquisition cost,
':'aendacommercieal paper ondits woulds
-:OPCo must pay the difference to'JMG.
purchase a maximum of' $600. million of
\\
purhase maxium of$600 nillin of
'The use of JMG 'allows OPCo to enter into an receivables from AEP Credit, of which $454 T
use o M a P
t million was outstandi
.A col s f operating lease while keeping the tax benefits receivables sold occur and are remitted, the otrwcte wa outstading alanc for sld reeivabes is of December 31,20,unless the structure of reduced and as new receivables aresold,ththis arrangement is changed, it is reasonably orustanng blasnce of s
rescvable possible that AEP and OPCo will consolidate inctrsetases.
,All ofe the-rSeceivaebles sold -
JMG in the third quarter of 2003 as a result of receivbles.'
The the issuance of FIN 46. Upon c'onsolidation, represented~ affiliate receivabl s Thef
., AEP and OPCo would record the assets, commitment's new term under the sale of lAbtEs,dpeiPin.xese mnrt receivables agreement will remain at $600 terest and debt interest expense of JM.
million until May 28, 2003.
APCredit i
maintainsa retaind interes
'in the AEP and OPCo would eliminate operating
maintains a
retaine'd'- interest 'in the' geaPaeXpeC--dEssadPPog receivables sold and this interest is pledged laeepne APsadOC' as' collateral for-the collection of the maximum exosure tlssas a rel othi receiablessold.The air vlue o the involvement with JMG is aipproximately $560.
reeintres is. bsed onab value duthe million of outstanding debt and equity of JMG
'to' the short-term nature of the accounts aso December
, 2 receivables less an allowance for anticipated uncollectible accounts.
d o
Pa U
2 t-0
-~~~~
' $- AEGCo and I&M---entered into a sale and See Note 23 "Lines of Credit and Sale ofGC an aetere int a slan Receivables" for further disclosure.-o.esbc rnacin i
99 wt Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated -trustee for Gavin Plant's flue gas desulfurization svstem Rockport Plant Unit 2 (the plant).
Owne (Gavin Scrubber) f
' 0 - ;' ;
Trustee was capitalized with equity from six
'OPCo has entered into an agreement wih -
owner participants with no relationship to AEP JMPG Funsding LLdP nt(JMG) an nre elawtetd
' or any of its subsidiaries and debt from a 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:
0 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 '
&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 debtand 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 the Owner Trustee. can sell the plant.
AEGCo, I&M nor AEP has ownership interest in the.Owner Trustee and do not guarantee its debt..
Summary Obligation Information
- ~~~~~~~~~~~~~~~biire inc 'd amut reore on
-th 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
_ear 2-3 ears 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 7
. 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 ontractual cash obligations LMZ (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 registrant's 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
. i
. I
In ddition to the amounts disclosed intecnracta caholtos tabl abve, AEP and its subsidiaries mk co itesin te norma course o f business. These comrmitmients includ standby letters of crei,gaanesfrthe payment o ol itn prformance bonds, andote 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 f redit (a)>
S 125
$1 40;
$ 166.
.Guarantees of the Performance of outside Parties.(b)
.1 17 325 17-492 Guarantees of our Performance
-1,159 2
'82.
9':
1,252 construction of Generating and Transmission Facilities fr Third Parties c)
.671 83
-47 67 868 other commercial.
Commitments d) 14 53 1178 Total ommercial commitments, 1
~
1
~
(a) AEP has standby letters of credit to third parties.
These-letters of creditcover gas and electricity trading contracts yarious construction contracts.and credit enhancement for issued bonds. All of these letters o# 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 J~anuary 2003 to December 2007. There is no liability recorded for these letters of credit in accordance with FIN 45..
ince AEP iS the parent to all these subsidiaries, it.
holds all assets of the subsidiary as collateral."Tee.
sn 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 NoteI.0 Cc) As construction agent for third party owners of power plants and transmission facilities,- AEP has committed by contract terms to complete constrtuction by datestspecified in the contracts, should AEP default on these obliations, financial payments could be up o 100% of contract value (amount shown in table) or other remedies required by contract.terms.
Cd) Represents estimated future payments for power.to be'generated at facilities unaer 'construction.
M-10 a
t II I
7
.1
I i
. I L
With the exceptions of SWEPCo's guarantee of an unaffiliated mine operator's obligations (payable upon'their default) of $148 million at December 31, 2002, and OPCo's obligations under a power purchase agreement of $14 '
million each'year in 2003 through 2005,' the obligations in the 'above table are commitments of AEP and its non-registrant subsidiaries.
OPCo has entered into a 30-year power purchase agreement for electricity pro-duced by an unaffiliated entity's three-unit natural:-
gas fired plant. The plant was completed in.
2002 and the agreement will terminate in 2032. Under the terms of the agreement, OPCo has the option to run the 'plant until
.'December31, 2005 taking 100% of the power-generated and making' monthly capacity payments., The capacity payments are fixed through December'2005 at $1.2 million per month. For the remainder of the 30. year" contract term, OPCo will pay the'variable costs to generate the electricity it purchases which could be' up to 20% of the, plant's' _'-
capacity. The estimated fixed payments are included in the Other Commercial, Commitments table shown above.
Expenditures for domestic electric utility construction are estimated to be $4 billion for the next three years. Approximately 90% of.
those construction expenditures are expected to be financed by intemally generated funds.
Construction expenditures for certain registrant subsidiaries for the next three years
-are:
- i Projected construction xpendi tures Construction Expenditures --
Financed with
- Internal Funds Cin millions)
APCo
$1,005 70%
I&M 601 90 OPCo 733 100 SWEPCo 351 -100 TCC 419 100--
A AE
.s
- u:
',b APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been seeking regulatory approval to build a, new high
'voltage transmission line for over a decade.
Certificates have'been issued by both the WVPSC and the Virginia SCC authorizing construction and operation of the line.- On December31,2002, the United States Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion ofthe line.
APCo expects additional state and federal' permits'to be issued in the first half of 2003.
Through December 31, 2002, APCo has invested 'approximately' $51 'million 'in this effort. The line is estimated to cost $287 million including amounts'spent to date with completion in 2006. If the required permits are not obtained and the line' is not:
constructed, the $51 million investment would be written off adversely affecting future results of operations and cash flows.
Pension Plans AEP -maintains qualified defined benefit pension plans' (Qualified Plans), which cover
'substantially all non-union and certain union
'associates, and unfunded excess' plans to provide benefits in excess -of amounts.
permitted to' be paid under the provisions of the tax law to' participants in the Qualified Plans.' Additionally, AEP has entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits.
AEP's pension income for all pension plans approximated $69 million and $44 million for the years ended December 31,-2001 and December 31, 2002, respectively, and is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Qualified Plans' assets of 9%. In developing the expected long-term rate of return assumption, AEP evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. AEP also-considered historical returns of the investment markets as well as AEP's-10-year average return (for the period ended 2002) of 8.8%.
AEP anticipates that the investment managers will continue to generate long-term returns of at least 9.0%. The expected long-term rate of return'on the Qualified Plans' assets is based on an asset allocation assumption of 70% with'-equity managers, with' an expected long-term rate of return of
- t s
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 December31, 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'th 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 illion 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 $6 million in 2003 increasing to approximate
.$108 million per year by 2005.
Critical Accounting Policies In the ordinary course of business, AEP an its registrant subsidiaries.. have. made number of estimates and assumptions relatin to the reporting of results of operations an financial condition in the preparation of the financial statements in conformity wit accounting principles generally accepted i the United States of America. Actual resuli could differ significantly from those estimate under different assumptions and condition.
They believe that the following discussio addresses the most. critical accountin policies, which are those that are mo, important to the portrayal. of the financic condition and.
results and requir management's most difficult, subjective an complex judgments, often as a result of th need to make estimates about the effect c matters that are inherently uncertain.
Revenue Recoqnition Regulatory Accounting - The consolidate financial statements of AEP and the financiz statements of electric operating subsidiar companies with cost-based rate-regulate operations (I&M, KPCo, PSO, and a porbon c APCo, OPCo, CSPCo, TCC' TNC an SWEPCo) reflect the' actions of regulator that can result in the recognition of revenue and expenses in different time periods thai enterprises that are not rate regulated. II accordance with SFAS 71, regulatory asset (deferred expenses to be recovered in thi future)' and regulatory liabilities (deferrei future revenue'reductions or refunds) ar recorded to reflect the economic effects c regulation by matching expenses with thei recovery through'regulated revenues in thi
' same accounting period and by matchini income with its passage to customers througl regulated revenues in the same accountinx period.,
Regulatory liabilities: are alsi recorded to provide for refunds to ustomerz
-: >::that have not yet been made.
When regulatory assets: are probable o
-recovery through regulated rates, they recort them as: assets on the balance sheet..The
- . test for probability of recovery whenever nev 6
events occur, for example,.issuance of a ly regulatory commission order or passage of new legislation.i If they' determine that recovery of a regulatory asset is no' longer probable, they write-off that regulatory asset as a charge, against earnings.' A write-off of id regulatory assets may also reduce future cash a
flows since there may be no recovery through ig regulated rates.
d Dir Traditional Electricity Supply and Delivery h
Activities -. Revenues are recognized on the n
accrual or settlement basis for normal retail Is and wholesale electricity supply sales and s
electricity transmission and -distribution delivery services.
The revenues are n
recognized in our statement of operations g
when the energy is delivered to the customer st
. and include unbilled as well as billed ial
. amounts. In general, expenses are recorded e
when purchased electricity is received and d
when expenses are incurred.
e of
'Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when d
services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered Xd -
gas.
Substantially all of the forward gas purchase ds f and. sale contracts, excluding wellhead Ls
-.'purchases of natural gas, swaps and options n
- for the domestic pipeline operations, qualify n
In.as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and 9
..losses resulting from revaluation of these ed --
contracts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net
)fr of applicable credit and liquidity reserves.
Energy Marketing and Trading Activities -In 2000, 2001 and throughout the majority of h
2002, AEP engaged in broad non-regulated wholesale. electricity, natural gas and other commodity marketing and trading transactions (trading activities)..AEP's trading activities involved the purchase and sale of energy under forward contracts at fixed and variable if
' prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-v M-13 i
I
- I i
1.,
L i I
.I.
counter options and swaps.
We used the the contract price and the' market price as 'an mark-to-market method of accounting for unrealizedgain or-loss in reven'ues. In July trading activities as required by EITF, Issue when the contract settles, we would realize a..
No. 98-10, "Accounting'for Contracts Involved
.gain or loss in cash and reverse to revenues' in 'Energy Trading and Risk Management:
the previouslyrecorded 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 fair value are
-' :'sales contract and the 'realized cost for a recorded net as revenues.
PSuch 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 'contract's 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 toTCC, 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. Prior to Pool (APCo, CSPCo, I&M, KPCo andOPCo);-
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.:
- '...... ;. ' 0.
.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 TNCand 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-outsideof 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
-netbasis,'.- : ' - '...i':-:
- .09!.
' '. '-':. trading contract' asse 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.
Prior to settlement, changes in the fair value of physical forward' sale and 'purchase contracts in AEP's traditional marketing area are also included in' revenues on a net basis.
Physical forward sale and purchase contracts for delivery` outside of AEP's traditional marketing area are included in nonoperating income when the contract settles.
Prior to settlement,' changes in the fair value of
- physical forward sale and purchase contracts with delivery. 'points outside of AEP's traditional marketing area are included in nonoperating income on a net basis.
Continuing with the above example for AEP, APCo, CSPCo, OPCo, TCC, and a portion of TNC and SWEPCo, assume that later in January or sometime in Februarythrough July we enter into an offsetting forward contract to buy energy in July. If we do nothing else with these contracts until settlement in July and if the commodity type, volumes, delivery point, schedule and other key terms match, then the difference between the sale price 'and the purchase price represents a fixed value to be realized when the contracts settle in July.
Mark-to-market accounting for these contracts from this point forward will have no further impact on operating,'results but has an offsetting and equal effect on trading contract assets and liabilities. If the sale and purchase contracts do not match exactly as to commodity type, volumes, delivery 'point, schedule and other key terms,'then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using MTM accounting..
For AEP, the trading of energy options, futures and swaps, represents' financial transactions with unrealized gains and losses from changes in fair values reported net in revenues uitil the contracts settle. When these contracts settle, we record the net proceeds in revenues, and reverse to revenues the prior cumulative unrealized net gain or loss. APCo, CSPCo, &M, KPCo and OPCo also have financial transactions, but record the' unrealized gains and losses, as well as the net proceeds upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on exchange prices and broker quotes.
We mark-to-market open long-term trading contracts based primarily on valuation models that estimate future energy prices based on'existing market'and broker quotes and supply and demand market data and assumptions.' The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due to AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and
'demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading' contracts.
We have independent controls to evaluate the reasonableness' of our valuation models.
- However, energy
- markets, especially electricity markets, are imperfect and volatile.
Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and at the time contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with AEP's approach' at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.
AEP applies MTM accounting to derivatives that are not trading contracts in accordance with generally accepted accounting principles.
Derivatives are contracts whose value is derived from the market value 'of an underlying commodity.
Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing us to 'market risk and causing our results of operations to be subject to volatility. See Note 17, "Risk Management, Financial Instruments and Derivatives" for a discussion of the,' policies and procedures' used to manage our exposure to market and other risks from trading activities.
Given the previously discussed reduction in AEP's trading activities, the impact of mark-to-market accounting on our financial 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, wehave
.'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 in the-
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: 0 :' 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. aftempt 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 materiallyfromactualresults
'resultsof operations, cash flows or financial du'e to changing market, and economic-'
condition.Thefollowingtableshowsthehigh, conditions, higher or lower withdrawal 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, mpact to the amount of pension expense 2002 2001 impctded.
- - ^' -
- e 0.
High Average Low
'-High Average Low recorded.
'(in millions)
~~~~~~~~~~~~~~AEP 24 S12
$4 :.-$28
$14
$5 New Accountinq Pronouncements S
$28
$5 APCO 4
1 4
1 See. Note 1 to -the consolidated financial I&M 3
1 1
statements. for 'a discussion of significant op
' 4 1-1 accounting policies: and new accounting,,
2 1
-SWEPCO:
.3 1
pronouncements-:.
3' TCc 1
TNC- -
M-16;
After the October 'announcement. of our strategy to reduce trading activity, the related VaRs were substantially, reduced.
The average AEP trading VaR for the 'fourth quarter 2002 was $7 million as compared to
$13 million for fourth quarter 2001. In 2003 we will continue to adjust our VaR limit structure commensurate with our anticipated level of trading activity.
We also utilize a VaR model to measure
'interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one year holding period. The volatilities and correlations were based on three years of weekly prices. The risk of potential loss in fair value attributable to-AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $527 million at December 31, 2002 and $673 million at December 31, 2001. However, since we would not expect to liquidate our entire debt portfolio in a one year holding period, a near term change in interest rates should not materially affect results of operations or consolidated financial position.
The following table shows the potential loss in fair value as measured by VaR allocated to the AEP registrant subsidiaries based upon debt outstanding:
VaR for Registrant Subsidiaries:
2 De2cember 31.
2002 20 (inmillions) comDanv AEGCO
$3 5
APCo
.87 100 CSPCo 33 60 I&MI
.85.
86 KPCo 30 16 OPCo 34 59 PSO 70 17 SWEPCo 70 36 TCC 65 80 TNC.
5 20 AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance operations since financing costs are recovered through the unit power agreements.
AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity'where generation is no longer regulated or where: existing fuel clauses are' suspended or frozen.
The protection afforded by fuel clause recovery mechanisms has-either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in the ERCOT area of Texas
'(effective January 1, 2002 for TCC and TNC) or frozen by settlement agreements in Michigan-and West Virginia or capped in Indiana. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected 'against market price changes by active;fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, gas and to a lesser degree other commodities and as a result we are subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Company's Chief Risk Officer and his staff. When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.
We employ, fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk.
We employ'cash flow forward hedge contracts to lock-in prices on certain power trading transactions denominated in foreign currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in foreign currencies. We do not hedge all foreign currency exposure.
Credit Risk AEP limits credit risk by extending unsecured credit to entities based on internal ratings. In addition, AEP uses Moody's Investor Service, M-17
Standard and Poor's 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 iand 2001 were the ratings information, is used to determine
'$109 million and $55 rmillion,- 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 -
Euivalents 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 December31,2002.-
$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 coun-ea Fo.Futures,waa prices. Forward price curves are developed Credit Qualitv Swa contracts Ontions Total i:;
for inclusion in the model based on broker n't-cp -nrs nther avaiIhl ma;rket drita. The AAAExchanges
.AA' A
- BBB Below Investment
- Grade Total 26 307-448
. 700 in millions)
I : $ 2 33 26
'101 107 11
.~~
sm The counterparty credit quality ar for the registrant subsidiaries i consistent with that of AEP.
We enter into'transactions for el natural gas as part of wholes operations. Electric and gas tran!
executed over the counter with co or through brokers. Gas transacti executed through brokerage' ac brokers who are registered
'Commodity Futures Trading C Brokers and'counterparties reqL 28
~
liquid portion of these curves are validated on 340 '
a regular basis by the middle-office through 474 the market data. Illiquid portions of the curves 801; -.-
are validated through a review of the 118 underlying market assumptions and variables for consistency and reasonableness. The end of the month liquidity reserve is based on the difference in price between the price curve id exposure and the bid price if we have a long position is generally and the price curve and the ask price if we have a short position. 'This provides for a more accurate valuation of energy contracts.
actricity and sale trading sactions are
,unterparties ons are also'..
counts with with the
,ommission.
uire cash or The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to
,.evaluate the'reasonableness of the price curve models. 'Significant adverse or favorable effects on future results of operations.'and cash flows could occur if M-18 t.
market prices, at the time of settlement, do not correlate with our interally developed price models.
The effect on the Statements of Operations of marking to market open electricity trading contracts in AEP's -regulated jurisdictions, specifically l&M, KPCo, PSO and a portion of SWEPCO, is deferred as regulatory assets (losses) or liabilities (gains) since these transactions are included in cost of service on a settlement basis for ratemaking purposes.
Unrealized mark-to-market gains and losses from trading are reported as assets or liabilities.
The following table shows net revenues (revenues less fuel and purchased:energy expense) and their relationship to the rmark-to-market revenues (the change in fair value of open trading contracts).
December 31.
2002 2001 2000 (in millions)
Revenues (including Mark-To-Market Adjustment)
$14,555
$12,767
$11,113 Fuel and Purchased Energy Expense 6.307 4 944 3.880 Net Revenues Mark-to-Market Revenues
$1i S207 SIZ Percentage of Net Revenues Represented by Mark-to-Market On open Trading Positions 2%
3%
3%
M-19 I,
The following tables analyze te changes in fair values of trading assets and liabilities. The first tble "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 i the Consolidated Balance Shets line itm"nry Trading and Derivative Contracts." The next table "Mark-to-Market Energy Trading and Derivative Contracts" disaggregates realized and unrealized canges in fair value;,'identifies changes in fair value as cha res ult of changes in valuation methodologies; and reconciles the net fair value of en'ergy trading contracts and related derivatives at December 31, 2001 of $448 million to December 31, 2002 of $250 million. Contracts realized/s,ettled 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.
Decembe r 31 2002 2001 (in millions)
Energy Trading and Derivative Contracts:
Current Asset
$1,046-2,5 Long-term Asset 824 795:
current Liability
.(1,147)
( 1,877)
Long-term Liability (484) 60 Net Fair value of Energy Tradin and Derivative contracts 23 440 Noni-trading related derivative Yiabilities 1*-
ASsets held for sale (citiPower).
___8 Net Fair alue of Energy Trading and Derivative contracts, L2i 48
- 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,Ttl (in iiiTiiTons)
Net Fai r Val ue of Energy Trading and Derivative ContrActs at December 31, 2001
$448 (Gain) LS from ontracts Realized/settled During,the Period (182)
Fair Value of New Open Contracts when Entered Into During'the Period.
- 68 Net option Premiums Pid/CReceived)
C130)
Lnange in air vaiue uUe TO etnouoiogy nanges Change in Market value of Energy Trading Contracts Allocated to Regulated Jurisdictions changes in arket value of ontracts-Net Fair value of EnergY Tra ding and Derivative ontracts at Dece mber 31,, 2002 M-20.
I 47 C
a)
I(b)
C c)
C d)
Ce).
IC f)
Mark-to;Market Energy Trading and Derivative Contracts - Registrant Subsidiaries APCo CSPCo Net Fair Value of Energy Trading-
$ 7 48,449 contracts at December 31, 2001 S 75,701
$ 48 449 (Gain) Loss from Contracts Realized/settled During the Period (a)
(19,143)
(13,812)
Change in Fair value Due To..
Methodologv changes (d) 350 228 Changes in Fair Market value of Energy Trading Contracts Allocated To Regulated Jurisdictions (e)
Fair value of New open Contracts when Entered Into during The Period (b)
Net option Premium Payments (c)
Changes In Market value of contracts (f)
Net Fair Value of Energy Trading Contracts at December 31, 2002 (g) 10, 865 (1,797)
- 30. 876 7,039 (1,208)
I 24.421 Net Fair value of Energy Trading contracts at December 31, 2001 (Gain) Loss From Contracts Realized/Settled During Period (a)
Change in Fair value Due To Methodology changes (d)
Changes In Fair Market value of Energy Trading Contracts Allocated To Regulated jurisdiction (e)
Fair Value of New Open Contracts when Entered Into During Period (b)
Net option Premium Payments (c) changes In Market Value of contracts (f)
Net Fair value of Energy Trading Contracts at December 31, 2002 (g)
Net Fair value of Energy Trading Contracts at December 31, 2001 (Gain) Loss From Contracts Realized/settled During The Period (a)
Change in Fair value Due To Methodology changes (d) changes In Fair Market value of Energy Trading Contracts Allocated To
- Regulated jurisdiction:(e)
Fair Value of New Open Contracts
.-when Entered Into During The Periodr(b)
Net option Premium Payments Cc) changes In Market value of Contracts (f)
Net Fair Value of Energy Trading contracts at December 31, 2002 (g)
KPCo
$12,729 1,153 90 5, 136 1,013 (464) 5.34 SWEPCo S 2,900 6,971 36 (2,485) 428 (3.800) oPCo
$ 65,446 (18, 337) 311 18,443 (1,603)
- 29. 846 TCC S 3, 857 7,138 42 1,919 (7.542)
$ 5414 (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.
(c) Net option Premiums Paid/(Received)" reflects the net option premiums paid/(received) 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)"Chan es 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 canges 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 I&M
$61, 345 (9,611) 247 1, 502 2,774 (1, 292) 15.896 PSO
$ 2,434 6.476 32 (5, 397)
TNC 915 2,413 12 (336) 1, 627 (2.588) 5-2-04
Mark-to-Market Energy Trading and Derivative Contract Maturitie - AEP Fair Value of Contracts Iat December 31. 2002
/
AEP Consolidated source of Fair alue PriceS Atively Quoted (a)
Prices Provided by other External~
Sources b)
Prices.Based on Models and other valuation ethods C),
Total I-la LUI IL Cb (i n millions)
Less than 1 year 1-3:years 4-5-years
$(32)
.$69 24, 189
-II (84)
~ 13 36 Mark-to-Market Energy Trading and Derivative Contract Maturities-Registrant Subsidiaries Fai rvalue of contracts at December 31. 2002 maturities (in thousands) source of Fair alue Less than IIn Ecess
.1 yea r 1-3 years.4-5 years of 5 years APCo Prices Provided by other External ources Cb)
$14,352
$43,307
$ 3,018
$ 60,677 PriceS Based on models and other valuation methods Cc) 31 492 9 475 8 183 7.025 36 175 Total
$25!844_
CSPCo Prices-Provided by other External ources Cb)
Prices Based on odels and other valuation ethods c)
Total KPCo Prices Provided by other
.External-Sources Cb)
Prices Based on odels and other valuation ethod s Cc)
Total I&M Prices Provided by other' External ources Cb)
Prices Based on odels'and ther valuation ethods Cc)
Total OPCo Prices provided by other EXternal ources Cb)
Prices Based on models and valuation ethods C)
Total other
$ 9657 7 726
$29,113
- $ 2,028 5.501 5LL1
$ 3,707
$11,176 779 2 966
- 2442 2 114
$12,105 7.913
$20, 775 10.003 1$30,961
- $38,622
. 8 453
$S 2,171 5 886 2,691 r7.298
$ 40,798 4 722 24 319
.$ 15,1662 1 814
- 9.336
$~
45,237 5 053 25.624
~$
62,088 6,264 32 018 PS0 Prices rovided by other External ources Cb)
Prices Based on models and other Valu tion ethods Cc)
Total SWEPCo Prices Provided by other" External sources (b)
Prices Based on models and other valuation ethods Cc),
Total
~TCC Prices Provided by other External Sources Cb)
Prices Based on odels and other valuation methods Cc)-
Total 373
$1, 736
.$,:427 390
$1, 983 338 446 1, 536-
$ 1,605
- 1. 219-361 M-22 336 141 385 115
.311 289 51zM
$ 2,234 1 311
- ~S
$ 2,551 330 1 499 S 310
-267
$ 3,256
- 2.158 in xces 2fL5years'
~24
. S 2A Total Fair
- value
-$37
- 224 (11)
Total Fai r Val ue
. II
TNC Prices Provided by other External Sources (b) 201
$1,016
$ 73 S 1,290 Prices Based on Models and other Valuation Methods (c) 159 229 197' 168 753 Total 3
1210 LJ&8 (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 categorv (c)"Prices Based on Models and other valuation Methods" contain the following: the vaTue 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
-7
,r
-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
-' -.f funds. The trust investments and their fair Statements.
value are discussed in Note 17, "Risk '
Management, Financial Instruments --and
- Corporate Separation 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 SECseeking 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 transfer the liability are expected to be recovered through generation assets from the integrated electric regulated rates from ourregulated 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 recovery0to 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 no t 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 longerowngeneration 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.t the nts w
state-regulatory supply-of electricity.':As legislative and.
commissions'and: other major intervenors regulatory proceedings evolved, six AEP were filed with the'FERO 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, genieration
- Terms in the settlement agreements would be
- business.
AEP has not discontinued its effective upon implernentation of corporation
'regulatory accounting for its subsidiaries separation. '
In addition', SEC approval of doing business in Michigan'(l&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,AEPanditssubsidiariesmaybe M-24
,required to retire various debt securities and transfer assets between legal entities.
With the changes in AEP's business strategy
-in response to current energy market/business conditions, management is evaluating changes, to the corporate separation
- plans, including determining whether legal corporate separation is appropriate.,
RTO Formation FERC Order No. 2000 and many of the settlement agreements with the FERC and state regulatory commissions to approve the AEP-CSW merger required the transfer of functional control of the subsidiaries' transmission systems to RTOs.
AEP East companies initially participated in the formation of the Alliance RTO.
In December 2001, the FERC reversed prior approvals and rejected the Alliance RTO's filing..
Subsequently, in May 2002, AEP
".announced an agreement with the PJM Interconnection to pursue terms for AEP East companies to participate in PJM with final agreements to be negotiated. In July 2002, the FERC conditionally approved AEP's decision forAEP East companies to join PJM subject to certain conditions being met. The performance of these conditions are only partially under AEP's control.. In December 2002, AEP East companies. in Indiana, Kentucky, Ohio and Virginia filed for state regulatory commission approval of their plans to transfer functional control of their transmission assets to,. PJM-based on statutory or regulatory requirements in those states.
Those proceedings are,. currently pending..
In February 2003, the Virginia
- DLegislature enacted legislation that would prohibit the transfer. to an RTO, until at least July 2004, which is currently awaiting signature by the Governor of Virginia.
AEP West companiesr are members of ERCOT or the SPP. In May 2002, FERC.
-accepted, conditionally, filings related to a proposed consolidation of the MISO and the SPP. In that order the FERC required the AEP West companies in SPP to file reasons.
why they should not be required to join MISO.
In August 2002, AEP, SWEPCo and TNC.
notified the FERC of their intent that the transmission assets in SPP would participate in MISO. AEP's SPP companies are also regulated by state public utility commissions, and the Louisiana and Arkansas commissions also filed responses to the FERC's RTO order indicating that additional analysis was required.
Regulatory activities concerning various RTO issues are ongoing in Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, AEP and its subsidiaries' transmission operations or future results of operations and cash flows.
FERC Proposed Standard Market Design and Security Standards In 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking seeking to standardize the structure and operation of wholesale electricity markets across the country. The FERC published for comment its proposed security standards as part of the SMD. These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities.
Because the rule is not yet finalized, management cannot predict the effect' of' the final rule on AEP or its subsidiaries' operations and financial results.
See Note 9 for a complete discussion of these proposals.
Litigation AEP and its subsidiaries are involved in various litigation. The details of significant litigation contingencies are disclosed in Note 9 and summarized below.
Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo In 2002, certain subsidiaries of AEP filed claims-in the bankruptcy proceeding of the Enron Corp. and its subsidiaries which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, AEP and its subsidiaries
.had -. open trading contracts and trading M-25
Th
- ea ing
.'r rw 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 Bammelgasstorage facilityand:
(n millions)"
the cushion gas (orpad gas) required for its APCo
$ 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 Court's decision. See cumulative loss of $53 million ($34 million net Note 18 for further discussion.
- 'of tax). The 'amounts for certain subsidiary Shaehode' L
a Ac AEP
- : - ':regisrantswee:
f0
-f-
- - -Sha,reholders'Litigation Aff6cting-AEP
-f registrants were:
Amounts In -2002, lawsuits alleging securities law Amounts Net of '
violations, a breach offiduciarydutyforfailure
'Registrant Expensed Tax to establish and maintain adequate-intemal (n
millions) controls and violations of the Employee Retirement Income Security Act were filed APCo
'$5.3
$3.4 against AEP,-; certain AEP -executives,,-
CSPCo 2.7
.8
-'members of the AEP Board.of Directors and I&M 0 \\
2.8 1.8 certain investment banking firms.
These KPCo 1.3, 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 California Lawsuit -- Affecting AEP registrant subsidiary. The amounts expensed:
were based on an analysis of contracts where In 2002, the Lieutenant Governor of California AEP entities and Enron are counterparties.
filed a lawsuit in California Superior Court
-against forty energy companies, including
-,'Management believes th'at 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 reportng of false natural gas price entities by offsetting'- approximately $110
- and volume information with an intent to affect million of trading payables owed to various the market price of natural gas and electricity.
e s t due -'
AEP intends to vigorously defend against this
~Enron entities against trading rieceivables acindeeNtueorfrhrdicsin
.action.
See Note 9 for further discussion.
to us. Management believes we have legal, f defenseis to any challenge that may be madeD f 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; Note9 for further-discussion.
'with FERC '-alleging 'that
- TNC, had C
-A-fectingAEP, -Po
&M, at.-.:.:-'-overcharged them through the fuel adjustment
.::COLI-AffectingAEP, APCo, CSPCo, &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'sconsolidated federal Merger:Litigation,- Affecting AEP and all income tax returns related to a COLI program-Subsidiay Registrants resulted in.a $319 million reduction in AEP's
-Net Income for 2000.
'.In January 2002, iafederal court ruled that the M-26
-SEC-did not properly find that the June 15, 2000 merger of AEP with CSW'meets the, requirements of the PUHCA and sent the case back to the SEC for further review.
Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. See Note 9 for further discussion.
Arbitration of Williams Claim - Affecting AEP In 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies
-(Williams).-.:. The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries.
Althni inh manaIment is unable to nredict the FERC issued an order delaying the effective date of the: mitigation plan until after a planned technical conference on market power deterrnination.
No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows Other Litigation -
Affecting AEP and all Subsidiary Registrants AEP and its subsidiaries are involved in a number. of. other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on results of operations, cash flows or financial condition.
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 -Affecting AEP 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.
i 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 energ y r natura 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 AEP and its subsidiaries have and will
'gas, emissions and avert global climatic
-.-. AEP and its 'subsidiaries. hae and -will,
'c.hangeS i
continue to provide information to the FERC, changes.
the SEC, state 'officials and the CFTC as AEP andits 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 X
control technologies.
AEP and
- its, required certain nitigation 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
'whiie providing vital energy commodities and required the posting of information on our services to customers at fairprices.
website regarding the status of AEPs 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 q
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 c'apital 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 SeeNote9forfurtherdiscussion.
emissions from electric generating plants.
N R
A AEP and its subsidiaries are advocates of I&MOPC, SWEPCand 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 estabish
- .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 i '-
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 for AEP companies.
applicable state and Federal NOx
- requirements including selective. catalytic
-Federal EPA Complaint and Notice of
- ;reduction (SCR) and non-SCR technologies.
Violation-Affecting AEP, APCo, CSPCo, l&M The AEP System NOx compliance plan is a and OPCo
~~~~~~~~~dynamic plan that is continually.reviewed and revised. Current estimates indicate that Since 1999 AEPSC, APCo, CSPCo, &M,and compliance withthe NOx Rule, the Texas OPCo ave ben inolvedin liigatin Comission on Environmental Quality rule regarding generating plant emissions under and the Section-126 Rule could result in
'the Clean Air'Act. Federal EPA, a number of, eurdcptlepniue nterneo sta-.
tesCiandspecial inrActeresgroEP allege tha-t'
' $1.3 billion to $2 billion of'w'hich $843 million AEP System companies modified certain units' has been spent through December 31, 2002 at coal fired generating plants in violation of f t A
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
t..,...............................results of', 'o,e!ations,.
I tos instnce
-. 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 AEP's registrant subsidiaries named a PRP or defendant, their disposal or through December 31, 2002.
recycling activities were in accordan'e with
'the then-applicable laws and regulations.
-Unfortunately, Superfund does not recognize Etimated Amounts Comliance Costs Spent compliance as a defense, but imposes strict (in millions) liability on parties who fall within its broad CompanY
- Q
$234 0
0.:;
statutory categories.
-APCo
$445
$234 I&M 42-210 5
Whilethe potential liabilityforeachSuperfund OPCo 535-840 387
-site must be evaluated separately, several
- TCC 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
- 0 -.-
' named as PRPs for each site and several of Superfund and State Remediation -Affecting the parties are financially sound enterprises.
AEP, APCo, CSPCo, l&M, OPCo, SWEPCo Therefore, our present estimates do not and TCC anticipate material cleanup costs for identified t-: '.
.: ' L. '
-:sites for which AEP subsidiaries have been By-products from the generationofelectricity 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 futureunderSuperfund, resultsofoperations, 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 arebeneficially utilized..
In addition, our, generating plants and Global'ClilatelChange -Affecting AEP and transmission and 'distribution facilities have allRegistrant Subsidianes 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 complywith 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-emission's 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 subsidiariesof signed the Kyoto Protocol on November 12, AEParenamedbytheFederalEPAasaPRP, 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 l&M hastwo PRP President Clinton. In March 2001, President sites. There are six additional sites for which -
Bush announced his opposition to the treaty APCo, CSPCo,:l&M, -KPCo, OPCo and
- and itsU.Sratification.
At the Seventh SWEPCo have received information requests Conference of the Parties in November 2001, which could lead to PRP designation. HPL, tpi nzd the rules, procedures and OPCo, SWEPCo and TCC have also been guidelines required to facilitate ratification of named potentially'-liable at six sites under-.
theprotcol. The protocol is expected to state law. Liability has been resolved for a become effective in-2003. AEP does not number of sites'with nosignificant effect-on
-M-29
supporttheKyotoProtocolbutintendstowork
'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' safelydispose 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 participateinthe 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 depositedinexternaltrustfunds to providefor
..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.:':-
- -beganoperation in the late 1980s. Underthe 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.
Control~
~
~ of Mecr Emsios c
s e
-. U..;-
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 responsibilityforSNF, 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 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 oth'er things, that the D.C Circuit 2003 and develop a final.rule in -2004.
Court order DOE to meet itsobligations 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 Smaterial.
- However, site for the nuclear waste will not be ready unless any capital 'and ' operating costs of until at least 2010.
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 effe'ct 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. In'August 2000, in an appeal TCC of related cases involving other unaffiliated utilities, the U.S. Court'of'App6als for the I&M, as the owner of the' Cook Plant,- and Federal Circuit held that the delays clause of M-30
. f~~~~~~~~~~~~~~~~~a
the standard contract between utilities and the DOE did not apply to DOE's complete failure to perform its contract obligations, and that 0- 0 the utilities' suits against DOE may continue in court. On January17, 2003, the U.S. Court of
-Federal Claims ruled in favor of l&M on the
-issue of liability. The case continues on the issue of damages owed to l&M by the DOE.
As long as the delay iri the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage of SNF and the cost of decommissioning will continue to increase.
In January 2001, l&M and STPNOC, on behalf of STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related to DOE's nuclear waste fund cost recovery settlement with PECO Energy Corporation (now Exelon Generation Company, LLC). The settlement adjusted the fees Exelon was required to pay to DOE for disposal of SNF.
The fee adjustment allowed Exelon to skip payments to the DOE to make up for Exelon's damages from DOE's breach of its contract obligation to dispose of SNF from commercial nuclear power plants. The companies believe the settlement was unlawful as it would force other utilities (rather than DOE) to compensate Exelon for the damages it had incurred from DOE's breach of contract. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly by adopting the fee adjustment provision of this settlement, that the fee adjustment provisions of the settlement harmed other utilities who pay, into the fund and violated the federal nuclear waste management laws > and that the fee adjustment provisions of the settlement were null and void.
The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNE disposal program. Studies completed in 2000 estimate the cost to decommission the Cook Plant ranges from
$783 million to $1,481 million in 2000 non-discounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant.
At December 31,- 2002, the total decom-missioning trust fund balance for Cook'Plant was $618 million which includes earnings on the trust investments. Studies completed in 1999; for STP estimate TCC's share of decommissioning cost to be $289 million in 1999 non-discounted dollars.
Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2002, the total decommission-ing trust fund for TCC's share of STP was $98 million which includes earnings on the trust investments.
Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site.
I&M and TCC will work with regulators and customers'to recover the remaining estimated costs of'decommissioning Cook Plant and STP. However, AEP's, I&M's and' TCC's future'results of operations, cash flows and possibly their financial conditions would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
Other Environmental Concerns - Affecting AEP and all Subsidiaries AEP and its subsidiaries are exposed to other environmental concerns which are not considered to be material or potentially material at this time. Should they become significant or, should any new concerns be uncovered that are material, they could have a material adverse effect on results of operations and possibly financial condition.
AEP performs environmental reviews and audits on 'a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues.
Other Matters Seasonalitv Sale of electric power is generally a seasonal business.
In many parts of the country, demand for power peaks during the hot summer months, with market. prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change depending on the nature'and location of facilities AEP and its subsidiaries acquire and the, terms of power sale contracts they enter. In addition, AEP and its subsidiaries have historically sold
'i M-31
- ~
~ ~ ~ ~~~~~~~~~~
less power, and consequently earned less Elk Citv Refei income, when weather conditions are milder.-
PSO AEP and its subsidiaries expect that unusually, mild weather in the future could diminish their In October 20C results of operations and may impact their City, Oklahom financial condition.,
seeking voter Sustained Earnings Improvement Initiative:
acquisition ot F the city limit rendum -
Affectinq AEP and
)2, the City Commission of Elk a voted to hold a referendum approval of a $20.4 million ISO's distribution assets within
- s.
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.
1 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 i
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 foi Settlements and Curtailments of Definec Benefit Pension Plans and for Terminatior Benefits". In addition, certain buildings anc corporate aircraft are being sold in an effort tc reduce ongoing operating expenses.
See Note 11 for additional information.
Non-Core Wholesale Investments Additional market deterioration associatec with AEP's non-core wholesale investments including AEP's U.K. operations, could havE an adverse impact on AEP's future results o operations and cash flows. Significant long term changes in external market conditions could lead to additional write-offs anc potential divestitures of AEP's wholesalE investments, including, but not limited to AEP's U.K. operations.
Our investment, including guarantees of debt, in certain types of activities is limited by PUHCA. SEC authorization under PUHCA
.limits us to issuing and selling securities in an amount up to 100% of our average quarterly consolidated retained earnings balance for investment in EWGs and FUCOs.
At December 31,-2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including guarantees of debt, compared to AEP's limit of $2.8 billion.i SEC rules under PUHCApermitAEPto invest up to 15% of consolidated capitalization (such amount was $3.2 billion at December 31, 2002) in energy-related companies, including marketing and/or trading of electricity, gas and other energy commodities.
f X
- -..0 :-.
0 f
0
- l.
. - r D i
i X
z 4
S D
't 0'
J L
X, X
H N
S \\
dl.
f s
r S
i f
[=
s f
' i
'S L
r e S..
E L'
i' L
.' T f
f '
2 '
- . 0.
. 9
, f 0
- . Z
,
- C t.:'
f 0 -- 0 --
- X
0 w-M-320n 0 ;
0 w.,
S 7.-
d A.
f
-' X :
i I.
.I
0
- S W
4
-This page intentionally: left blank.-
f 9
f...
S -
- J
- 111, t
I
ATTACHMENT 2 TO AEP:NRC:3071-02 INDIANA MICHIGAN POWER COMPANY PROJECTED CASH FLOW FOR THE YEAR 2003
2003 Forecasted Internal Cash Flow
$ Millions 2003 Net income After Taxes Less: Common & Preferred Dividends 65.32 40.00 25.32 Adjustments:
Depreciation and Amortization Amortization of Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Changes in Working Capital Total Adjustments Internal Cash Flow Average Quarterly Cash Flow Average Cash Balances and Short-Term Investments Total Projected 173.45 56.21 (28.25)
(6.86)
(0.02) 194.53 219.85 54.96 2.93 57.89