ML021360189
| ML021360189 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/10/2002 |
| From: | Greenlee S Indiana Michigan Power Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| AEP:NRC:2691-11 | |
| Download: ML021360189 (151) | |
Text
Indiana Michigan Power Company Cook Nudear Plant One Cook Place Bndgman, MI 49106 616&465-5901 INDIANA MICHIGAN POWER May 10, 2002 AEP:NRC:2691-11 10 CFR 50.71 10 CFR 140.21 Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P 1-17 Washington, D.C. 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 2001 FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Indiana Michigan Power Company (I&M) hereby submits, as At achrer;t
- 1.
thc I&M 2001 Annual Financial Report in accordance with 10 CFR 50.7t(b)o Also included, as Attachment 2, is a copy of the year 2002 projected cash flow for I&M as required by 10 CFR 140.21 (e).
This letter contains no new commitments.
Should you have any questions, please contact Mr. Gordon P. Arent, Manager of Regulatory Affairs, at (616) 697-5553.
Sincerely, A. Greenlee Director of Design Engineering and Regulatory Affairs DB/dmb Attachments c:
K. D. Curry, w/o attachments J. E. Dyer MDEQ - DW & RPD, w/o attachments NRC Resident Inspector R. Whale, w/o attachments mq uu ALP-America's Energy Partnze.-
ATTACHMENT 1 TO AEP:NRC:2691-11 INDIANA MICHIGAN POWER COMPANY 2001 ANNUAL REPORT Sections B through E and Sections G through K have been omitted from this attachment in order to provide only information relevant to the Licensee, Indiana Michigan Power Company.
2001 Annual Reports American Electric Power Company, Inc.
S.AEP Generating Company Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Audited Financial Statements and Management's Discussion and Analysis.
Z,AMERICAN ELECTRIC POWER ALI': -,Americds EnemyTg Partner
Contents Page Glossary of Terms i
Forward Looking Information iv American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Income A-12 Consolidated Balance Sheets A-13 Consolidated Statements of Cash Flows A-15 Consolidated Statements of Common Shareholders' Equity and A-16 Comprehensive Income Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-17 Schedule of Consolidated Long-term Debt of Subsidiaries A-1 8 Index to Notes to Consolidated Financial Statements A-19 Management's Responsibility A-20 Independent Auditors' Report A-21 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B-4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Notes to Financial Statements B-8 Independent Auditors' Report B-9 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of C-7 Comprehensive Income Consolidated Balance Sheets C-8 Consolidated Statements of Cash Flows C-1 Consolidated Statements of Retained Earnings C-I I Consolidated Statements of Capitalization C-12 Schedule of Long-term Debt C-13 Index to Notes to Consolidated Financial Statements C-14 Independent Auditors' Report C-15 Central Power and Light Company and Subsidiaries Selected Consolidated Financial Data D-1 Management's Discussion and Analysis of Results of Operations D-2 Consolidated Statements of Income D-6 Consolidated Balance Sheets D-7 Consolidated Statements of Cash Flows D-9 Consolidated Statements of Retained Earnings D-1O0 Consolidated Statements of Capitalization D-11 Schedule of Long-term Debt D-12 Index to Notes to Consolidated Financial Statements D-13 Independent Auditors' Report D-14
Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Narrative and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-10 Schedule of Long-term Debt E-11 Index to Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-1 3 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Discussion and Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of F-7 Comprehensive Income Consolidated Balance Sheets F-8 Consolidated Statements of Cash Flows F-10 Consolidated Statements of Retained Earnings F-1 1 Consolidated Statements of Capitalization F-12 Schedule of Long-term Debt F-13 Index to Notes to Consolidated Financial Statements F-15 Independent Auditors' Report F-16 Kentucky Power Company Selected Financial Data G-1 Management's Narrative Analysis of Results of Operations G-2 Statements of Income, Statements of Comprehensive Income G-6 and Statements of Retained Earnings Balance Sheets G-7 Statements of Cash Flows G-9 Statements of Capitalization G-10, Schedule of Long-term Debt G-11 Index to Notes to Financial Statements G-12 Independent Auditors' Report G-13 Ohio Power Company and Subsidiaries Selected Consolidated Financial Data H-1 Management's Discussion and Analysis of Results of Operations H-2 Consolidated Statements of Income and Consolidated Statements of H-7 Comprehensive Income Consolidated Balance Sheets H-8 Consolidated Statements of Cash Flows H-10 Consolidated Statements of Retained Earnings H-1i1 Consolidated Statements of Capitalization H-12 Schedule of Long-term Debt H-1 3 Index to Notes to Consolidated Financial Statements H-1 5 Independent Auditors' Report H-16
Public Service Company of Oklahoma and Subsidiaries Selected Consolidated Financial Data Management's Narrative Analysis of Results of Operations Consolidated Statements of Income and Consolidated Statements of Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt Index to 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 Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Capitalization Schedule of Long-term Debt Index to Notes to Consolidated Financial Statements Independent Auditors' Report West Texas Utilities 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 Schedule of Long-term Debt Index to Notes to Consolidated Financial Statements Independent Auditors' Report Notes to Financial Statements Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters I-1
(-2 1-5 1-6 1-8 1-9 1-10 1-11 1-12 J-1 J-2 J-6 J-7 J-9 J-10 J-11 J-12 J-1 3 K-1 K-2 K-6 K-7 K-9 K-10 K-1I K-12 K-1 3
- ....*.
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 Meaning 2004 True-up Proceeding......... A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs.
AEGCo................
AEP Generating Company, an electric utility subsidiary of AEP.
AEP...........................................
American Electric Power Company, Inc.
AEP Consolidated..................... AEP and its majority owned subsidiaries consolidated.
AEP Credit,lnc.
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating 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 electric operating com panies................................
AFUDC.....................................
Alliance RTO.............................
Am os Plant...............................
APCo........................................
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 Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities.
John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
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, an AEP electric utility subsidiary.
CSPCo.................
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW.........................................
Central and South West Corporation, a subsidiary of AEP.
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 M ining 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.
FM B.................
................... First M ortgage Bond.
FUCOs......................................
Foreign Utility Companies.
GAAP........................................
Generally Accepted Accounting Principles.
I&M...........................................
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPC............................................
Installment Purchase Contract.
IRS............................................
Internal Revenue Service.
IURC.........................................
Indiana Utility Regulatory Commission.
ISO............................................
Independent system operator.
Joint Stipulation.........................
Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo........................................
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC........................................
Kentucky Public Service Commission.
KWH.........................................
Kilowatthour.
LIG............................................
Louisiana Intrastate Gas.
Michigan Legislation................. The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.
Midwest ISO.............................
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.
MTN..........................................
Medium Term Notes.
MW...........................................
Megawatt.
MWH.........................................
Megawatthour.
NEIL..........................................
Nuclear Electric Insurance Limited.
Nox...........................................
Nitrogen oxide.
NOx Rule..................................
A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operates.
NP.............................................
Notes Payable.
NRC..........................................
Nuclear Regulatory Commission.
Ohio Act....................................
The Ohio Electric Restructuring Act of 1999.
Ohio EPA..................................
Ohio Environmental Protection Agency.
OPCo........................................
Ohio Power Company, an AEP electric utility subsidiary.
OVEC........................................
Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.
PCBs.........................................
Polychlorinated Biphenyls.
PJM...........................................
Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP..........................................
Potentially Responsible Party.
PSO..........................................
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO.......................................
The Public Utilities Commission of Ohio.
PUCT........................................
The Public Utility Commission of Texas.
PUHCA.....................................
Public Utility Holding Company Act of 1935, as amended.
PURPA.....................................
The Public Utility Regulatory Policies Act of 1978.
RCRA........................................
Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............. AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU.
Rockport Plant..........................
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.
RTO..........................................
Regional Transmission Organization.
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 Tvoes of Reaulation.
ii
1I1 SFAS 101.................................
Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of Application of Statement 71.
SFAS 121.................................
Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.
SFAS 133.................................
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
S N F...........................................
Spent N uclear Fuel.
SPP...........................................
Southwest Power Pool.
STP...........................................
South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light 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 CPL.
Superfund.................................
The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo..................................
Southwestern Electric Power Company, an AEP electric utility subsidiary.
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.
Travis District Court................. State District Court of Travis County, Texas.
TVA..........................................
Tennessee Valley Authority.
UX............................................
The United Kingdom.
U N.............................................
U nsecured Note.
VaR...........................................
Value at Risk, a method to quantify risk exposure.
Virginia SCC.............................
Virginia State Corporation Commission.
W V............................................
W est V irginia.
WVPSC....................................
Public Service Commission of West Virginia.
WPCo.......................................
Wheeling Power Company, an AEP electric distribution subsidiary.
WTU.........................................
West Texas Utilities Company, an AEP electric utility subsidiary.
Yorkshire...................................
Yorkshire Electricity Group plc, 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 This discussion includes forward-looking statements within the meaning of Section 21 E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors both foreign and domestic that could cause actual results to differ materially from forward looking statements are: electric load and customer growth; abnormal weather conditions; available sources of and prices for coal and gas; availability of generating capacity; risks related to energy trading and construction under contract; the speed and degree to which competition is introduced to our power generation business; the structure and timing of a competitive market for electricity and its impact on prices, the ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states; the timing of the implementation of AEP's restructuring plan; new legislation and government regulations; the ability to successfully control costs; the success of new business ventures; international developments affecting our foreign investments; the economic climate and growth in our service and trading territories both domestic and foreign; the ability of the Company to successfully challenge new environmental regulations and to successfully litigate claims that the Company violated the Clean Air Act; inflationary trends; litigation concerning AEP's merger with CSW; changes in electricity and gas market prices and interest rates; fluctuations in foreign currency exchange rates, and other risks and unforeseen events.
iv I..
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AMERICAN ELECTRIC POWER COMPANY, INC.
AND SUBSIDIARY COMPANIES
III AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 INCOME STATEMENTS DATA (in millions):
Total Revenues
$61,257
$36,706
$24,745
$18,420 Operating Income 2,395 2,004 2,304 2,258 Income Before Extraordinary Items and cumulative Effect 1,003 302 986 975 Extraordinary Losses (50)
(35)
(14) cumulative Effect of Accounting change 18 Net Income 971 267 972 975 Year Ended December 31, BALANCE SHEETS DATA (in millions):
Property, Plant and Equipment Accumulated Depreciation and Amortization Net Property, Plant and Equipment Total Assets Common shareholders' Equity 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 Extraordinary Item and Cumulative Effect Extraordinary Losses Cumulative Effect of Accounting change Earnings Per Share Average Number of shares Outstanding (in millions)
Market Price Range: High 2001
$40,709 2000
$38,088 16,166 15,695 1999
$36,938 15,073 1998
$35,655 1997
$11,427 2,180 949 (285) 664 1997
$33,496 14,136 13,229
$ 24.543
$~22393
$21 5
~$20,26Z
$47,281
$53,350
$35,693
$33,418
$30,092 8,229 156 321 8,054 161 334 12,053 10,754 451 2001
$ 3.11 (0.16) 0.06 322 614 2000
$0.94
(.11) 322
$51.20
$48-15/16 8,673 182 335 11,524 610 1999 8,452 350 335 11,113 539 1998
$3.07
$3.06
(.04) 321
$48-3/16 318
$53-5/16 8,220 V
377 335 9,354 549 1997
$2.99
(.90)
$2-0-9 316 52 Low 39.25 Year-end Market Price Cash Dividends on Common**
Dividend Payout Ratio**
Book Value per Share 43.53
$2.40 79.7%
$25.54 25-15/16 30-9/16 42-1/16 39-1/8 46-1/2 32-1/8 47-1/16 51-5/8
$2.40 289.2%
$25.01
$2.40 79.2%
$26.96
$2.40 78.4%
$26.46 The consolidated financial statements give retroactive effect to AEP's merger with was accounted for as a pooling of interests.
- Including portion due within one year
"*Based on AEP historical dividend rate.
$2.40 114.8%
$25.91
- CSW, which A-I
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Management's Discussion and Analysis of Results of Operations American Electric Power Company, Inc.
(AEP) is one of the largest investor owned electric public utility holding companies in the US. We provide generation, transmission and distribution service to over 4.9 million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. We market and trade electricity and natural gas in the US and Europe.
We have a
significant presence throughout the domestic energy value chain.
Our US electric assets include:
38,000 megawatts of generating capacity (the largest US generation portfolio with a
significant cost advantage in the Midwest and Southwest markets);
38,000 miles of transmission lines and 186,000 miles of distribution lines Our natural gas assets include:
128 Bcf of gas storage facilities 0
6,400 miles of gas pipelines in Louisiana and Texas which provide a basis for market knowledge.
With our coal and transportation assets we:
"* control over 7,000 railcars
"* control over 1,800 barges and 37 tug boats
"* operate two coal handling terminals with 20 million tons of capacity.
"* produce over 7 million tons of coal annually in the US.
AEP is one of the largest traders of electricity and natural gas in the US:
"* over 576 million MWH of electricity trades in 2001
"* over 3,800 billion cubic feet (Bcf) of gas trades in 2001 In addition we:
"* consume 80 million tons of coal annually
"* consume 310 Bcf of natural gas annually AEP's focus is in the US but we also have smaller footprints in other parts of the world:
a growing energy trading operation in Europe based in the UK.
4,000 megawatts of generating capacity in the United Kingdom which represents 16% of the UK's total generation capacity.
Other foreign investments include distribution operations in the U.K., Australia, and Brazil. We have additional generating facilities in China and Mexico. We also offer engineering and construction services worldwide.
Business Strategy Our strategy is a balanced business model of regulated and unregulated businesses backed by assets, supported by enterprise-wide risk management and a strong balance sheet. We have been focused on the wholesale side of the business since it provides the greater growth opportunities. But, this is complemented by a robust regulated business that has a predictable earnings stream and cash flows.
Strong risk management and a disciplined analysis of markets protected us from the California energy crisis and Enron's bankruptcy filing.
Our balanced business model is one where AEP integrates its assets, marketing, trading and market analysis and resources to create a superior knowledge about the commodity markets which keeps us a step ahead of our competition. Our power, gas, coal, and barging assets and operations provide us with market knowledge and customer connectivity giving us the ability to make informed marketing and trading decision and to customize our products and services.
AEP provides investors with a balanced portfolio since it has:
"* a growing unregulated wholesale energy marketing and trading business
"* predictable cash flow and earnings A-2
streams from the regulated electricity business, and a high dividend yield relative to today's low-interest rate environment.
We are currently in the process of restructuring our assets and operations to separate the regulated operations from the non-regulated operations.
We filed with the SEC for approval to form two separate legal holding company subsidiaries of AEP Co. Inc., the parent company. Approval is needed from the SEC under the PUHCA and the FERC to make these organizational changes. Certain state regulatory commissions have intervened in the FERC proceedings. We have reached a settlement with those state commissions and are awaiting the FERC's approval before the SEC will make a final ruling on our filing.
We are implementing a
corporate separation restructuring plan to support our objective of unlocking shareholder value for our domestic businesses. Our plan provides for:
"* transparency and clarity to investors,
"* a simpler structure to conduct
- business, and to anticipate and monitor performance,
"* compliance with states' restructuring laws promoting customer choice, and
"* more efficient financing.
The new corporate structure will consist of a regulated holding company and an unregulated holding company. The regulated holding company's investments will be in integrated utilities and Ohio and Texas wires.
The unregulated holding company's investments will be in Ohio and Texas generation, independent power producers, gas pipe line and storage, UK generation, barging, coal mining and marketing and trading.
The risks in our business are:
"* Margin erosion on electric trading as markets mature,
"* Diminished opportunities for signifi cant gains as volatility declines,
"* Retail price reductions mandated with the implementation of customer choice in Texas and Ohio,
"* Movement towards re-regulation in California through market caps and other challenges to the continuation of deregulation of the retail electricity supply business in the U.S.,
"* The continued negative impact of a slowly recovering economy.
Our business plan considers these risks and we believe that we can deliver earnings growth of 6-8% annually across the energy value chain through the disciplined integration of strategic assets and intellectual capital to generate these returns for our shareholders.
Our strategies to achieve our business plan are:
Unregulated "o Disciplined approach to asset acquisition and disposition "o Value-driven asset optimiz ation through the linkage of superior commercial, an alytical and technical skills "o Broad participation across all energy markets with a
disciplined and opportunistic allocation of risk capital "o Continued investment in both technology and process im provement to enhance our competitive advantage "o Continued expansion of intellectual capital through ongoing recruiting, perform ance-linked compensation and the development of a structure that promotes sound decision making and innovation at all levels.
Regulated "o Maintain moderate but steady earnings growth "o Maximize value of trans mission assets and protect revenue stream through RTO/Alliance membership "o Continue process improve ment to maintain distribution service quality while en hancing financial performance "o Optimize generation assets through enhanced availability of off-system sales A-3
o Manage regulatory process to maximize retention of earnings improvement Our significant accomplishments in 2001 were:
"* Adding the following assets to integrate with and support our trading and marketing competitive advantage:
o 4,200 miles of gas pipeline, 118 Bcf gas storage and re lated gas marketing contracts o
1,200 hopper barges and 30 tugboats o 4,000 megawatts of coal-fired generation in England o
160 megawatts of wind generation in Texas o
coal mining properties, coal reserves, mining operations and royalty interests in
"* Entering into new markets through the acquisition of existing contracts and hiring key staff including 57 employees from Enron's London based international coal trading group in December 2001 and Enron's Nordic energy trading group in January 2002.
We now trade power and gas in the UK,
- France, Germany, and the Netherlands and coal throughout the world
"* Adding other energy-related commodities to our power and gas portfolio i.e. coal, S02 allowances, natural gas liquids (NGLs) and oil
"* Disposing of the following assets that did not fit our strategy:
"o 120 MWs of generation in Mexico, "o Above market coal mines in Ohio and West Virginia, "o A 50 % investment in Yorkshire, a U.K.
electric supply and distribution company, "o An investment in a Chilean electric company "o Datapult, an energy information data and analysis tool.
In addition we sold 500 MWs of generating capacity in Texas under a FERC order that approved our merger with CSW.
Our divesture of non-strategic assets is somewhat limited by the pooling of interest accounting requirements applied to the merger of CSW and AEP in June 2000. We are presently evaluating certain tele communications and foreign investments for possible disposal and have not yet decided whether to dispose of such investments.
Disposal of investments determined to be non-strategic will be considered in accordance with the pooling of interests restrictions which end in June 2002. We are committed to continually evaluate the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and shareholder value.
Any investment dispositions could affect future results of operations.
Outlook for 2002 Growth in 2002 will be driven in part by our continued strategic development of wholesale products and geographies, as demonstrated in recent months by our move into global coal markets and Nordic energy. A full year of operation of assets acquired in 2001 - Houston Pipe Line, Quaker Coal, the MEMCO barge line and two power plants in the United Kingdom - will also contribute to growth in 2002 earnings.
Although we expect that the future outlook for results of operations is excellent there are contingencies and challenges. We discuss these matters in detail in the Notes to Financial Statements and in this Management's Discussion and Analysis. We intend to work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our shareholders.
As discussed above we expect to continue evaluating certain investments for possible disposal due to either their non strategic nature or limited future earnings potential for AEP.
Any dispositions could result in gains or losses being recorded in our income statement.
A-4
Results of Operations In 2001 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 and coal "o Coal mining, bulk commodity barging operations and other energy supply related business.
"* Energy Delivery "o Domestic electricity trans
- mission, "o Domestic electricity distri bution Other Investments "o Foreign electric distribution and supply investments, Telecommunication services.
Net Income Net income increased to $971 million or
$3.01 per share from $267 million or $0.83 per share. The increase of $704 million or
$2.18 per share was due to the growth of AEP's wholesale marketing and trading
- business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. Also contributing to the earnings improvement in 2001 was 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. The favorable effect on comparative net income of these 2000 charges was offset in part by current year losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.
The decline in net income to $267 million or $0.83 per share in 2000 from $972 million or $3.03 per share in 1999 was primarily due to the 2000 charges described above and an extraordinary losses from the discontinuance of regulatory accounting for generation in certain states.
A strong performance in the first nine months of 2001 was partially offset by unfavorable operating conditions in the fourth quarter.
Extremely mild November and December weather combined with weak economic conditions in the fourth quarter, reduced retail energy sales and wholesale margins. Heating degree days in the fourth quarter were down 33% from the same period in 2000.
Although the fourth quarter was disappointing, 2001 net income before extraordinary items and cumulative effect of accounting change reached the $1 billion mark.
Our wholesale business continues to perform well despite a slowing economy that reduced both wholesale energy margins and energy use by industrial customers.
Our wholesale
- business, which includes generation, retail and wholesale sales of power and natural gas and trading of power and natural gas and natural gas pipeline and storage services, contributed to the earnings increase by successfully returning the Cook Plant to service in 2000 and by growing AEP's wholesale business.
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.
Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and declining short term market interest rate conditions.
A-5 JIII
,
A.
Critical Accounting Policies Revenue Recognition - Traditional Electricity Supply and Delivery Activities - As the owner of cost-based rate-regulated electric public utility companies, AEP Co.,
Inc.'s consolidated financial statements recognize revenues on an accrual basis for traditional electricity supply sales and for electricity transmission and distribution delivery services. These 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 incurred. As a result of our cost based rate regulated operations, our financial statements 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, "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 in the same accounting period regulated expenses with their recovery through regulated revenues.
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.
We discontinued application of SFAS 71 for the generation portion of our business in Ohio for OPCo and CSPCo in September 2000, in Virginia and West Virginia for APCo in June 2000, in Texas for CPL, WTU, and SWEPCo in September 1999 and in Arkansas for SWEPCo in September 1999 in recognition of the passage of legislation to transition to customer choice and market pricing for the supply of electricity.
We recorded extraordinary losses when we discontinued the application of SFAS 71. See Note 2, "Extraordinary Items and Cumulative Effect" for additional information.
Wholesale Energy Marketing and Trading Activities - We engage in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange futures and options and over-the-counter options and swaps.
Although trading contracts are generally short term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark to-market (MTM) accounting.
It represents the change in the unrealized gain or loss throughout the contract's term.
When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase.
A-6
Therefore, over the term of the trading contracts an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading and derivative contract assets or liabilities as appropriate.
The majority of our trading activities represent physical forward electricity and gas contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity or gas in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased energy expense for a purchase contract with the prior change in unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity or gas 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. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts.
Mark-to-market accounting for these contracts will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract.
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 mark-to-market accounting.
Trading of electricity and gas options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle. When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior unrealized gain or loss.
The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on Company-developed valuation models.
These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due 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 and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the Company-developed price models.
A-7 A A
Critical Accountinq Policies Revenue Recognition - Traditional Electricity Supply and Delivery Activities - As the owner of cost-based rate-regulated electric public utility companies, AEP Co.,
Inc.'s consolidated financial statements recognize
- revenues on an accrual basis for traditional electricity supply sales and for electricity transmission and distribution delivery services. These revenuesrate recognized in our income statement when the energy is delivered to the customer and include unbilled
- as well as billed amount, In general,
,,expenses are recorded whd incurred. As a result of our cost based*° rate regulated operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in
.-,,different time periods than eterprises that are not rate regulated. In accordance with SFAS "71, "Accounting for the* Effe-cts of Certain Ti"-rypes of Regulation,"* regulatory assets 41 (deferred expenses) and regulatory liabilities (future revenue reductiongor refunds) are recorded to reflect the economic effects of regulation by matching in the same accounting period regulated expenses with their recovery through regulated revenues.
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.
We discontinued application of SFAS 71 for the generation portion of our business in Ohio for OPCo and CSPCo in September 2000, in Virginia and West Virginia for APCo in June 2000, in Texas for CPL, WTU, and SWEPCo in September 1999 and in Arkansas for SWEPCo in September 1999 in recognition of the passage of legislation to transition to customer choice and. market pricing for the supply of electricity.
We recorded extraordinary losses when we disc~ontinued the application of SFAS 71. See Note:2, "Extraordinary Items and Cumulative Effept" for additional information.
Wholesale Energy Marketing and Trading Activities - We engage in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange futures and options and over-the-counter options and swaps.
Although trading contracts are generally short term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark to-market (MTM) accounting.
It represents the change in the unrealized gain or loss throughout the contract's term.
When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase.
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Therefore, over the term of the trading contracts an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading and derivative contract assets or liabilities as appropriate.
The 'najority of our tradin6 activities represent physical forward electricity and gas contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity or gas in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased energy expense for a purchase contract with the prior change in unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity or gas 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. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts.
Mark-to-market accounting for these contracts will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract.
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 mark-to-market accounting.
Trading of electricity and gas options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle.
When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior unrealized gain or loss.
The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on Company-developed valuation models.
These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due 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 and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the Company-developed price models.
A-7 jI I
We also mark to market 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.
Our revenues of $61 billion for 2001 included $257 million of unrealized net gains from marking to market open trading and derivative contracts.
AEP's net revenues, (revenues less fuel and energy purchases) excluding mark-to-market revenues totaled
$8.3 billion and were realized during 2001.
Unrealized net mark-to-market revenues are only 3% of total net revenues. A significant portion of the net unrealized revenues from marking to market trading contracts and derivatives included in our balance sheet at December 31, 2001 as energy trading and derivative contract assets and liabilities, will be realized in 2002.
We defer as regulatory assets or liabilities the effect on net income of marking to market open electricity trading contracts in our regulated jurisdictions since these transactions are included in cost of service on a settlement basis for ratemaking purposes.
Changes in mark-to-market valuations impact net income in our non-regulated business.
Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk causing our results of operations to be more volatile. See "Market Risks" section below for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities.
Revenues Increase Our revenues have increased significantly from the marketing and trading of electricity and natural gas. The level of electricity trading 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, has had a major effect on the volume of wholesale power marketing and trading especially in the short-term market.
AEP's total revenues increased 66.9%
in 2001 and 48.3% in 2000. The following table shows the components of revenues in millions.
WHOLESALE BUSINESS:
Residential commercial Industrial other Retail Customers For The Year Ended December 31 2001 2000 1999 (in millions)
$ 3,553 $ 3,511 $ 3,290 2,328 2,249 2,083 2,388 2,444 2,515 419 414 394 Electricity Marketing and Trading 35,339 18,858 11,417 Gas Marketing and Trading 14,369 6,127 2,290 unrealized MTM Income:
Electric 210 38 2
Gas 47 132 21 other 632 838 599 Less Transmission and Distribution Revenues Assigned to Energy Delivery*
3-i-5)3--(174) 30-68)
TOTAL WHOLESALE BUSINESS 55,929 31.437 19,543 ENERGY DELIVERY BUSINESS:
Transmission 1,029 1,009 960 Distribution 2,327 2,165 2.108 TOTAL ENERGY DELIVERY 3,356 3,174 3,068 OTHER INVESTMENTS:
SEEBOARD CITIPOWER other TOTAL OTHER INVESTMENTS TOTAL REVENUES 1,451 1,596 350 338 171 161 1,972 2,095 1,705 318 111 2,134
- Certain revenues in Wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.
The $25 billion increase in 2001 revenues was due to substantial increases in electric and gas trading volumes. The increase in sales of purchased power and purchased gas during the past two years reflect AEP's intention to be a leading national wholesale energy merchant.
Wholesale natural gas trading volume for 2001 was 3,874 Bcf, a 178% increase from 2000 volume of 1,391 Bcf. Electric trading volume increased 48% to 576 million MWH. We have invested in resources required to optimize our assets and emerge as a leader in the industry.
The maturing of the Intercontinental Exchange, the development of proprietary tools, and the increased staffing of energy A-8
traders have faciliated increased power and gas sales.
Our June 2001 purchase of Houston Pipe Line enhanced our gas trading and marketing operation. Although we will trade and market only when we believe profitable opportunites exist, we expect the increased level of activity to continue.
While wholesale marketing and trading volumes rose, kilowatthour sales to industrial customers decreased by 5% in 2001.
This decrease was due to the economic recession.
In the fourth quarter, sales to residential, commercial and wholesale customers declined 9%. The recession reduced demand and wholesale prices especially in the fourth quarter.
While margins available from selling power that the company generates generally are higher than from selling purchased power, such sales are limited by the amount of generating assets owned. Furthermore, the profit available from simply selling excess generation is reduced by the inherent market transparency of such sales. The coordinated sales of excess generation in conjunction with trading and marketing activity optimizes assets, mitigates risk, and increases overall profit.
The $12 billion increase in 2000 revenues was primarily due to a 27% increase in wholesale electricity trading volume and increased retail fuel revenues as a result of higher gas prices used to generate electricity.
The reduction in industrial revenues in 2000 is attributable to the expiration of a long-term contract on December 31, 1999.
The significant increase in 2000 electricity trading volume, which accounted for a 66% increase in electricity trading revenues, resulted from:
"* efforts to grow AEP's energy marketing and trading operations,
"* favorable market conditions, and
"* the availability of additional generation Generation availability improved due to the return to service of one of the Cook Plant nuclear units in June 2000 and to improved outage management. The second Cook Plant unit which returned to service in December 2000 did not have a significant impact on 2000 revenues. Gas revenues increased in 2000 due to increased natural gas and gas A-9 liquid product prices.
Operating Expenses Increase Changes in the components operating expenses were as follows:
of Increase (Decrease)
From Previous Year (Dollars in Millions) 2001 2000 Amount Amount
%o Fuel and PurchasedA Energy
$24,035 83.7 $11,474 66.5 Maintenance and other Operation 196 5.1 565 17.2 Non-recoverable Merger Costs (182)(89.7) 203 N.M.
Depreciation and Amortization 133 10.6 38 3.1 Taxes other Than Income Taxes
- 22) (3.2) 19)(2.7)
Total 6 69.6 i
54.6 Our fuel and purchased energy expense in 2001 increased 84% due to increased trading volume and an increase in nuclear generation cost. 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 costs.
Fuel and purchased energy expense increased 67% in 2000 due to increased trading volume and a significant increase in the cost of natural gas used for generation.
Natural gas usage for generation declined 5%
while the cost of natural gas consumed rose 60%. Net income was not impacted by this significant cost increase due to the operation of fuel recovery rate mechanisms. These fuel recovery rate mechanisms generally provide for the deferral of fuel costs above the amounts included in existing rates or the accrual of revenues for fuel costs not yet recovered.
Upon regulatory commission review and approval of the unrecovered fuel costs, the accrued or deferred amounts are billed to customers. With the introduction of customer choice of electricity supplier and a transition to market-based generation rates, the protection offered by fuel recovery mechanisms against changes in fuel costs was eliminated in Ohio effective January 1, 2001 and in the ERCOT area of Texas effective January 1, 2002. As a result, AEP's exposure to the risk of fuel price increases that could adversely affect future results of operations and cash flows is increasing. See Note 1 for applicability of fuel recovery mechanisms by jurisdiction.
ill1
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.
The increase in maintenance and other operation expense in 2000 was mainly due to increased expenditures to prepare the Cook Plant nuclear units for restart following an extended NRC monitored outage and increased usage and prices of emissions allowances. The increase in Cook Plant restart costs resulted from the effect of deferring restart costs in 1999 and an increase in the restart expenditure level in 2000. Cook Plant began its extended outage in September 1997 when both nuclear generating units were shut down because of questions regarding the operability of certain safety systems.
In 1999 a portion of incremental restart expenses were deferred in accordance with IURC and MPSC settlement agreements which resolved all jurisdictional rate-related issues related to the Cook Plant's extended outage. With NRC approval Unit 2 returned to service in June and achieved full power operation on July 5, 2000 and Unit 1 returned to service in December and achieved full power operation on January 3, 2001. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments, which became effective on January 1, 2000.
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 after the merger was consummated.
Depreciation and amortization expense increased in 2001 primarily as a result of the commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and West Virginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in property, plant and equipment.
Interest. Preferred Stock Dividends, Minority Interest Interest expense deceased 15% in 2001 due to the effect of interest paid the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.
In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest.
In 2000 interest increased by 17% due to additional interest expense from the ruling disallowing COLI tax deductions and AEP's effort to maintain flexibility for corporate separation by issuing short-term debt at flexible rates. The use of fixed interest rate swaps has been employed to mitigate the risk from floating interest rates.
Other Income Other income increased $166 million in 2001. This increase was primarily caused by the sale in March 2001 of Frontera, a generating plant required to be divested under a FERC approved merger settlement agree ment, which produced a pretax $73 million gain and the effect from the December 2000 impairment writedown of $43 million to reflect the pending sale of AEP's Yorkshire investment.
Other income decreased $66 million in 2000 primarily due to a loss in equity earnings from the 2000 write-down of the Yorkshire investment and losses from certain non regulated subsidiaries accounted for on an equity basis. Other expenses increased in 2000 mainly from a
charge for the discontinuance of an electric storage water heater demand side management program of the regulated business.
Income Taxes Although pre-tax book income increased considerably, income taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest A-10
deductions by the IRS and nondeductible merger related costs in 2000.
Income taxes increased in 2000 over 1999 levels primarily due to the disallowance of the COLI interest deductions and the non deductible merger related costs discussed above.
Extraordinary Losses and Cumulative Effect In 2001 we recorded an extraordinary loss of $48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation.
The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after tax extraordinary loss of $35 million.
New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark to market certain fuel supply contracts that qualify as financial derivatives.
The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a cumulative effect of accounting change.
A-11 II1
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Income (in millions - except per share amounts)
Year Ended December 31, 2001 2000 1999 REVENUES:
Electricity Marketing and Trading
$41,513
$25,178
$17,232 Gas Marketing and Tradin9 14,416 6,259 2,311 Domestic Electricity Delivery 3,356 3,174 3,068 Other Investment 1,972 2,095 2,134 TOTAL REVENUES 61,257 36,706 24,745 EXPENSES:
Fuel and Purchased Energy:
Electricity Marketing and Trading 37,558 21,246 13,646 Gas Marketing and Trading 14,004 6,227 2,305 other Investment 1,191 1,245 1,293 TOTAL FUEL AND PURCHASED ENERGY 52,753 28,718 17,244 Maintenance and other operation 4,037 3,841 3,276 Non-recoverable Merger Costs 21 203 Depreciation and Amortization 1,383 1,250 1,212 Taxes other Than income Taxes 668 690 709 TOTAL EXPENSES 58,862 34,702 22,44 OPERATING INCOME 2,395 2,004 2,304 OTHER INCOME 302 136 202 OTHER EXPENSES 130 81 42 LESS: INTEREST 972 1,149 977 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 10 11 19 MINORITY INTEREST IN FINANCE SUBSIDIARY 13 INCOME BEFORE INCOME TAXES 1,572 899 1,468 INCOME TAXES 569 597 482 INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT 1,003 302 986 EXTRAORDINARY LOSSES (NET OF TAX):
DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (48)
(35)
(8)
LOSS ON REACQUIRED DEBT (2)
(6)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 18 NET INCOME 971
$167 972 AVERAGE NUMBER OF SHARES OUTSTANDING 322 322 31 EARNINGS PER SHARE:
Income Before Extraordinary Item and Cumulative Effect
$ 3.11
$0.94
$3.07 Extraordinary Losses (0.16)
(.11)
(.04) cumulative Effect of Accounting change
.06 Earnings Per share (Basic and Dilutive)
$J1 "10B3 13-M CASH DIVIDENDS PAID PER SHARE
$2.40 S2_0_
12.40 See Notes to consolidated Financial Statements beginning on page L-1.
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- II AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (in millions - except share data)
December 31, 2001 2000 ASSETS CURRENT ASSETS:
cash and cash Equivalents 333 342 Accounts Receivable:
Customers 626 888 Miscellaneous 1,365 2,883 Allowance for Uncollectible Accounts (109)
(72)
Energy Trading and Derivative Contracts 8,572 15,497 Other 1,776 1,363 TOTAL CURRENT ASSETS 12,563 20,901 PROPERTY PLANT AND EQUIPMENT:
Electric:
Production 17,477 16,328 Transmission 5,879 5,609 Distribution 11,310 10,843 Other (including gas and coal mining assets And nuclear fuel) 4,941 4,077 Construction work in Progress 1,102 1,231 Total Property, Plant and Equipment 40,709 38,088 Accumulated Depreciation and Amortization 16,166 15,695 NET PROPERTY, PLANT AND EQUIPMENT 24,543 22,393 REGULATORY ASSETS 3,162 3,698 INVESTMENTS IN POWER, DISTRIBUTION AND COMMUNICATIONS PROJECTS 677 782 GOODWILL (NET OF AMORTIZATION) 1,494 1,382 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,370 1,552 OTHER ASSETS 2,472 2,642 TOTAL 47u.81 See Notes to Consolidated Financial Statements beginning on page L-1.
A-13
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31.
2001 2000 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES:
Accounts Payable
$ 2,245
$ 2,627 short-term Debt 3,155 4,333 Long-term Debt Due within one Year*
2,300 1,152 Energy Trading and Derivative Contracts 8,311 15,671 other 2,088 2,154 TOTAL CURRENT LIABILITIES 18,099 25,937 LONG-TERM DEBT*
9,753 9,602 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,183 1,313 DEFERRED INCOME TAXES 4,823 4,875 DEFERRED INVESTMENT TAX CREDITS 491 528 DEFERRED CREDITS AND REGULATORY LIABILITIES 948 637 DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 194 203 OTHER NONCURRENT LIABILITIES 1,334 1,706 COMMITMENTS AND CONTINGENCIES (Note 8)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH 321 334 SUBSIDIARIES MINORITY INTEREST IN FINANCE SUBSIDIARY 750 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES*
156 161 COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
2001 2000 shares Authorized.
.600,000,000 600,000,000 shares Issued.
.331,234,997 331,019,146 (8,999,992 shares were held in treasury at December 31, 2001 and 2000) 2,153 2,152 Paid-in capital 2,906 2,915 Accumulated other comprehensive Income (Loss)
(126)
(103)
Retained Earnings 3,296 3,090 TOTAL COMMON SHAREHOLDERS' EQUITY 8,229 8,054 TOTAL
$47,281
$53
- See Accompanying schedules.
A-14
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Cash Flows (in millions)
OPERATING ACTIVITIES:
Net Income Adjustments for Noncash Items:
Depreciation and Amortization Deferred Federal Income Taxes Deferred Investment Tax Credits Amortization (Deferral) of Operating Expenses and Carrying Charges (net)
Equity in Earnings of Yorkshire Electricity Group r Extraordinary Loss Cumulative Effect of Accounting Change 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 Utility Revenues Accounts Payable Taxes Accrued Premium Options 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 Purchase of Houston Pipe Line Purchase of U.K. Generation Purchase of Quaker Coal Co.
Purchase of Memco Purchase of Indian Mesa Sale of Yorkshire Sale of Frontera other Net cash Flows used For Investing Activities FINANCING ACTIVITIES:
Issuance of Common stock Issuance of Minority Interest Issuance of Long-term Debt 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 other Financing Activities Net Cash Flows From Financing Activities Effect of Exchange Rate change on cash Net Increase (Decrease) in cash and cash Equivalents Cash and cash Equivalents January 1 Cash and Cash Equivalents December 31 See Notes to Consolidated Financial Statements beginning 1Ic Year Ended December 31, 2001 2000 1999 971 267 972 1,413 163 (29) 40 50 (18) 340 (257)
(384) 1,764 (82) 26 (461)
(147)
(76)
(213)
C147) 2,953 (1,832)
(727)
(943)
(101)
(266)
(175) 383 265 (36)
C3 432) 10 747 2,931 (5)
(1,835)
(597)
(773)
(5) 473 (3)
(9) 342 E:333 1,294 180 (38)
(151)
(45) 14 (191)
(23) 101 (80)
(162)
(35) 74 29 8
(16)
(87)
(245) 1,599 (1,680) 19 7
1,754) 1,673) 14 1,124 (20)
(1,565) 1,308 (805) 56 23 (242) 584
$ý 342 93 1,391 (170)
(915) 812 (833)
(43) 335 (2) 259 325
$ 584 1,299 (170)
(36) 48 (44) 35 (449)
(170) 217 (1,632) 147 (79) 1,322 172 74 319 (92) 205 1,433 (1,773) on page L-1.
A-15 1II
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equity and Comprehensive Income (in millions)
JANUARY 1, 1999 Issuances Retirements and other cash Dividends Declared other com prehensive Income:
Other comprehensive Income, Net of Taxes Foreign currency Translation Adjustment Minimum Pension Liability Net Income Total comprehensive Income DECEMBER 31, 1999 Issuances cash Dividends Declared other com prehensive Income:
Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment Reclassification Adjustment For LOSS Included in Net Income Net Income Total comprehensive Income DECEMBER 31, 2000 Issuances cash Dividends Declared other com prehensive 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 Common Stock shares Amount 328
$2,134 3
15 331 331 M
2,149 3
2,152 1
Paid-In capi tal
$2,818 77 3
2,898 11 2,915 9
(18)
Retained Earnings
$3,493 (833)
(2) 972 3,630 (805)
(2) 267 3,090 (773) 8 971 Accumulated other comprehensive Income (Loss)
$7 (13) 2 (4)
(119) 20 (103)
(14)
(3)
(6)
See Notes to consolidated Financial Statements.
A-16 Total
$8,452 92 3
(833)
(2_)
7,712 (13) 2 972 961 8,673 14 (805) 4 7,886 (119) 20 267 168
$8,054 10 (773)
(10) 7,281 (14)
(3)
(6) 971 948 E>A &.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31, 2001 call Price per Shares Shares Amount (In share Ca)
AuthorizedCb)
Outstandinq(f)
Millions]
Not subject to Mandatory Redemption:
4.00% -
5.00%
$102-$110 1,525,903 614,608
$6J.
Subject to Mandatory Redemption:
5.90% -
5.92% (c)
(d) 1,950,000 333,100
$33 6.02% 7/8% Cc)
$100 1,650,000 513,450 52 7% (e)
Ce) 250,000 100,000 10 Total Subject to Mandatory Redemption (c)
$95 December 31, 2000 Call Price per Shares shares Amount (In share (a)
Authorizedb) outstandinoCf)
Millions)
Not subject to Mandatory Redemption:
4.00% -
5.00%
$102-$110 1,525,903 614,608 16 subject to Mandatory Redemption:
5.90% -
5.92% (c)
(d) 1,950,000 333,100
$ 33 6.02% -
6-7/8% (c)
$100 1,650,000 513,450 52 7% (e)
(e) 250,000 150,000 15 Total Subject to Mandatory Redemption (c) iiao NOTES TO SCHEDULE OF 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 invol untary liquidation preference is
$100 per share for all outstanding shares.
(b)
As of December 31, 2001 the subsidiaries had 13,642,750, 22,200,000 and 7,713,495 shares of $100,
$25 and no par value preferred stock, respectively, that were authorized but unissued.
(c)
Shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements.
The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed. The sinking fund provisions of the series subject to mandatory redemption aggregate (after deducting sinking fund requirements) of $5 million in 2002 and $5 million in 2003.
(d)
Not callable prior to 2003; after that the call price is
$100 per share.
(e) with sinking fund.
(f)
The number of shares of preferred stock redeemed is 50,000 shares in 2001, 209,563 shares in 2000 and 1,698,276 shares in 1999.
A-17
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries weighted Average Interest Rate December 31, 2001 Interest Rates at December 31, 2001 2000 December 31, 2001 2000 (in millions)
FIRST MORTGAGE BONDS (a) 2001-2003 6.95%
6.00%-7.70%
2004-2008 6.98%
6-1/8%-8.00%
2020-2025 7.66%
6-7/8%-8.80%
INSTALLMENT PURCHASE CONTRACTS (b) 2001-2009 4.30%
1.80%-7.70%
2011-2030 5.88%
1.55%-8.20%
NOTES PAYABLE (c) 2001-2021 5.41%
4.0483%-9.60%
SENIOR UNSECURED NOTES 2001-2004 4.81%
2.31%-7.45%
2005-2009 6.24%
6.125%-6.91%
2038 7.30%
7.20%-7-3/8%
JUNIOR DEBENTURES 2025-2038 8.05%
7.60%-8.72%
YANKEE BONDS AND EURO BONDS 2001-2006 8.71%
8.50%-8.875%
OTHER LONG-TERM DEBT (d)
Unamortized Discount (net)
Total Long-term Debt Outstanding (e)
Less Portion Due within one Year Long-term Portion NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES 5.91%-8.95%
6-1/8%-8%
6-7/8%-8.80%
4.90%-7.70%
4.875%-8.20%
6.20%-9.60%
6.50%-7.45%
6.24%-6.91%
7.20%-7-3/8%
7.60%-8.72%
7.98%-8. 875%
(a)
First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.
(b)
For certain series of installment purchase contracts interest rates are subject to periodic adjustment. certain series will be purchased on demand at periodic interest-adjustment dates.
Letters of credit from banks and standby bond purchase a reements support certain series.
(c)
Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions.
At expiration all notes then issued and outstanding are due and payable.
Interest rates are both fixed and variable.
variable rates generally relate to specified short-term interest rates.
(d) other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 8 of the Notes to consolidated Financial Statements) and financing obligation under sale lease back agreements.
(e)
Long-term debt outstanding at December 31, 2001 is payable as follows:
Principal Amount (in millions) 2002
$ 2,300 2003 2,086 2004 902 2005 616 2006 1,943 Later Years 4.246 Total Principal Amount 12,093 Unamortized Discount 40 Total A-18 Maturity 852 1,092 850 446 1,234 2,237 1,874 1,763 340 618 479 308 12,053 2,300
$ 1,247 1,140 1,104 234 1,447 1,181 2,049 475 340 620 684 280 (47) 10,754 1,152 I-
AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants.
The combined footnotes begin on page L-1.
Combined Footnote Reference Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 3
Nuclear Plant Restart Note 4
Rate Matters Note 5
Effects of Regulation Note 6
Customer choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Acquisitions and Dispositions Note 9
Benefit Plans Note 10 Stock-Based compensation Note 11 Business Segments Note 12 Risk Management, Financial Instruments And Derivatives Note 13 Income Taxes Note 14 Basic and Diluted Earnings Per share Note 15 Supplementary Information Note 16 Power, Distribution and Communications Projects Note 17 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Minority Interest in Finance subsidiary Note 22 A-19
MANAGEMENT'S RESPONSIBILITY The management of American Electric Power Company, Inc. 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 generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of 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, Deloitte & 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 next 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 Company's internal control structure over financial reporting.
A-20
t11 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.:
We have audited the consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, cash flows, and common shareholders' equity and comprehensive income for each of the three years in the period ended December 31, 2001. 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. The consolidated financial statements give retroactive effect to the merger of American Electric Power Company, Inc. and its subsidiaries and Central and South West Corporation and its subsidiaries, which has been accounted for as a pooling of interests as described in Note 3 to the consolidated financial statements. We did not audit the consolidated statements of income, and cash flows, and stockholder's equity and comprehensive income of Central and South West Corporation and its subsidiaries for the year ended December 31, 1999, which statements reflect total revenues of $5,516,000,000 for the year ended December 31, 1999. Those consolidated statements, before the restatement described in Note 3, were audited by other auditors whose report, dated February 25, 2000, has been furnished to us, and our opinion, insofar as it relates to those amounts included for Central and South West Corporation and its subsidiaries for 1999, is based solely on the report of such other auditors.
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 and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
We also audited the adjustments described in Note 3 that were applied to restate the 1999 financial statements to give retroactive effect to the change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied.
Deloitte & Touche LLP Columbus, Ohio February 22, 2002 A-21
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
[II
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NDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
- elected Consolidated Financial Data 2001 ENCOME STATEMENTS DATA
Operating Revenues Operating Expenses Operating Income (Loss)
Nonoperating Income (Loss)
Interest charges Net Income (LOSS)
Preferred Stock Dividend Requirements Earnings (Loss)
Applicable to Common Stock
$4,803,625 4,643,920 159,705 9,730 93,647 75,788 4,621 2000
$3,542,084 3,576,786 (34,702) 9,933 107,263 (132,032) 4,624 Year Ended December 31, 1999 (in thousands)
$2,920,187 2,811,535 108,652 4,530 80,406 32,776 1998
$2,435,646 2,.269,639 166,007 (839) 68,540 96,628 4,885 4,824 27.891 91,8_
1997
$1,391,917 1.,184,129 207,788 4,415 65,463 146,740 5,736
$ 141.00~4 2001 BALANCE SHEETS DATA:
Electric Utility Plant Accumulated Depreciation and Amorti zati on Net Electric Utility Plant Total Assets Common Stock and Paid-in capital Accumulated other comprehensive Income (LOSS)
Retained Earnings Total Common Shareholder's Equity Cumulative Preferred stock:
Not subject to Mandatory Redemption Subject to Mandatory Redemption (a)
Total Cumulative Preferred Stock Long-term Debt (a)
Obligations under capital Leases (a)
Total capitalization And Liabilities
$4,923,721 2,436,972
$2,~48679 2000
$4,871,473 2,280,521 December 31, 1999 (in thousands)
$4,770,027 2,194,397
$4,817,008
$5.811.038 789,800 (3,835) 74,605
$ 789,656 3,443 789,323 166,389 1998
$4,631,848 2,081,355
$2,550,4*93
$4.148. 2 789,189 253,154 1997
$4,514,497 1,973,937
$3, 967,798
$ 789,056 278,814 8,6
$ 793,099 955,712
$1,0427343 1
9,435 8,736 8,736 9,248 9,273 9,435 64,945 73,681 64,945 73,681 si4,817,008 64.,945 S
74,193
$1, 324.326
$4 1766965 4A5_4j6 59 68,445 77,718
$4,148,523 68,445 77,880
$1. 049. 237 195_ý 222
$3,967,798 (a) Including portion due within one year.
F-i
$_5,811,038
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Manaaement's Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 567,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers including power trading transactions. I&M also sells wholesale power to municipalities and electric cooperatives.
The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits.
AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs.
The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs.
I&M is committed under unit power agreements to purchase all of AEGCo's 50%
share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities.
AEGCo is an affiliate that is not a member of the AEP Power Pool. A long-term unit power agreement with an unaffiliated utility expired at the end of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity.
An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity.
Critical Accounting Policies -
Revenue Recognition Regulatory Accounting - As a cost-based rate regulated electric public utility company, I&M's consolidated financial statements 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) 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 in the same accounting period.
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 Delivery Activities - We recognize revenues on an accrual basis for 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 incurred.
F-2
Energy Marketing and Trading Activities AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to l&M as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts.
Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since I&M is a cost-based rate regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses).
The deferral reflects the fact that power sales and purchases are included in regulated rates on a settlement basis.
AEP's traditional marketing area is up to two transmission systems from the AEP service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis.
Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term.
When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement.
Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income.
When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area.
For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses 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. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate.
Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in non operating income until the contracts settle.
When these financial contracts settle, we record our share of the net proceeds in non operating income and reverse to nonoperating income the prior unrealized gain or loss.
F-3 4.
The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models.
These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due 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. AEP has independent controls to evaluate the reasonableness of our valuation models.
- However, energy
- markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP developed price models.
Volatility in commodities markets affects the fair values of all of our open trading contracts exposing I&M to market risk.
See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities.
Results of Operations During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection.
See discussion in Note 4 of the Notes to Financial Statements.
A reduction in other operation and maintenance expense in 2001 reflects the completion of restart work on the Cook Plant and was the primary reason for a $208 million increase in net income.
As a result of the costs incurred in 2000 to restart the Cook Plant nuclear units and a disallowance of interest deductions for a corporate owned life insurance (COLI)
- program, net income declined $165 million in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including I&M, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLL. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them.
Operating Revenues Increase Operating revenues increased 36% in 2001 and 21%
in 2000 due to increased wholesale marketing and trading sales. The following analyzes the changes in operating revenues:
Increase (Decrease)
From Previous Year (dollars in millions) 2001 2000 Amount Amount Retail
- Marketing and Trading other Energy Dellvery*
Sales to AEP Affiliates Total (2.3) N.M.
$(88.6)
(12) 1,210.7 52 5.0 13 1,213.4 40 3.4 1
44.7 21 LZ6IS 36 564.0 32 C13.0)
(26) 462.4 18 0.1 N.M.
159.4 313
$6-12 21 N.M.
= Not Meaningful
- Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
The increase in operating revenues in 2001 and 2000 is primarily due to an increase in wholesale marketing and trading activities.
The maturing of the Intercontinental Exchange, the development of proprietary tools, and increased staffing of energy traders have resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area.
A decline in retail revenues partly offset the increase in wholesale marketing and trading revenues. Retail revenues decreased in 2000 when the accrual of power supply recovery revenues ceased at the end of 1999 pursuant to Cook Plant settlement agreements. The F-4 IIl
accrued power supply recovery revenues are being amortized over a five-year period ending December 31, 2003.
I&M increased its sales to AEP affiliates in 2000 when additional electricity became available. The return to service of the Cook Plant units and purchasing more power from AEGCo due to the expiration of AEGCo's contract to sell power to an unaffiliated entity, increased the amount of power I&M could sell to its affiliates in the AEP Power Pool.
Operating Expenses Increase Total operating expenses increased 30% in 2001 and 27% in 2000 primarily due to additional purchases of power for marketing and trading and due to the expiration of an AEGCo unit power agreement to sell part of its Rockport Plant generation to an unaffiliated utility.
Also contributing to the increase in operating expenses in 2000 was the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts. The changes in the components of operating expenses were:
Increase (Decrease)
From Previous Year (dollars in millions) 2001 200U Amount Amount.
Fuel Marketing and Trading Purchases AEP Affiliate Purchases other operation Maintenance Depreciation an(
Amortization Taxes Other Thai Income Taxes Income Taxes Total 39.2 19 1,227.7 59 (27.2)
(10)
(147.8)
(25)
(92.6) (42) 9.3 6
4.9 8
53.6 N.M.
$.O.
30
$ 25.5 14 462.9 29 65.1 32 137.5 30 84.5 62 4.9 3
(5.2)
_ (9.)
(8)
(95) 27 N.M.
= Not Meaningful The increase in fuel expense in 2001 and 2000 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage.
Electricity marketing and trading purchased power expense increased in 2001 and 2000 due to AEP's effort to grow its wholesale marketing and trading business.
The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool. Purchases from the AEP Power Pool declined 21% in 2001. As a result of the expiration of AEGCo's power sale contract with an unaffiliated utility on December 31, 1999, I&M was obligated to buy more of AEGCo's share of Rockport Plant power.
Purchases from AEGCo increased 91% in 2000.
The decrease in other operation and maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook Plant nuclear units for restart with their return to service in 2000.
Other operation and maintenance expenses increased in 2000 primarily due to expenditures to prepare the Cook Plant units for restart.
In 1999 the IURC and MPSC approved settlement agreements which allowed the deferral of $200 million of Cook Plant restart costs in 1999 for amortization over five years from 1999 through 2003. As a result, other operation and maintenance expense in 1999 reflected a net deferral of
$160 million. See discussion in Note 4 of the Notes to Financial Statements.
The increase in depreciation and amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of I&M's share of deferred merger costs.
Taxes other than income taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment recorded in December 2000 to match estimated amounts with actual expenses. The decrease in taxes other than income tax in 2000 is primarily attributable to decreases in real and personal property taxes reflecting the favorable accrual adjustment and Indiana gross receipts taxes reflecting an unfavorable accrual adjustment related to the 1998 tax year recorded in 1999 for gross receipts tax.
The significant increase in income taxes attributable to operations in 2001 is due to an increase in pre-tax operating income. Income taxes attributable to operations decreased in 2000 due to a decrease in pre-tax operating income.
F-5 I,
Nonoperating Income and Expenses Increase The increases in nonoperating income and expenses in 2001 and 2000 is primarily due to increased volume of forward electricity trading transactions outside AEP's traditional marketing area. Nonoperating power trading revenues increased 70% in 2001 and 95% in 2000. Nonoperating power trading expenses increased 70% in 2001 and 93% in 2000.
Interest Charges The decrease in 2001 interest charges reflects the recognition in 2000 of deferred interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998.
Interest charges increased in 2000 due to increased borrowings to support expenditures for the Cook Plant restart effort and the recognition of deferred interest payments to the IRS on the disputed taxes.
F-6
ý I.
IDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES nnsolidated Statements of Income Year Ended December 31, 2001 2000 1999 (in thousands)
PERATING REVENUES:
Electricity Marketing and Trading Energy Delivery sales to AEP Affiliates TOTAL OPERATING REVENUES
)PERATING EXPENSES:
Fuel Purchased Power:
Electricity Marketing and Trading 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 TAX EXPENSE INTEREST CHARGES NET INCOME (LOSS)
PREFERRED STOCK DIVIDEND REQUIREMENTS
$4,234,176 314,410 255,039 4,803,625 250,098 3,293,255 238,237 451,195 127,263 164,230 65,518 54,124 4,643,920 159,705 1,474,572 1,459,799 5,043 93,647 75,788 4,621
$3,020,757 311,019 210,308 3,542,084 210,870 2,065,509 265,475 599,012 219,854 154,920 60,622 524 33,576,786 (34,702) 869,895 855,773 4,189 107,263 (132,032) 4,624
$2,558,338 310,880 50,969 2,920,187 185,419 1,602,658 200,372 461,494 135,331 149,988 65,843 10,430 2,811,535 108,652 452,019 446,183 1,306 80,406 32,776 4,885 EARNINGS (LOSS)
APPLICABLE TO COMMON STOCK Consolidated Statements of Comprehensive Income NET INCOME (LOSS)
OTHER COMPREHENSIVE INCOME (LOSS) cash Flows Interest Rate Hedge COMPREHENSIVE INCOME (LOSS)
See Notes to Financial statements beginning on page L-1.
Year Ended December 31, 2001 2000 1999 (in thousands)
$75,788
$(132,032)
$32,776 (3,835)
$711953
$(132.032) i2ll=
F-7 Sn1/2
[11 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets ASSETS ELECTRIC UTILITY PLANT:
Production Transmission Distribution General (including nuclear fuel)
Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS LONG-TERM ENERGY TRADING CONTRACTS OTHER PROPERTY AND INVESTMENTS CURRENT ASSETS:
Cash and Cash Equivalents Advances to Affiliates Accounts Receivable:
Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel - at average cost Materials and Supplies - at average cost Energy Trading Contracts Accrued Utility Revenues Prepayments TOTAL CURRENT ASSETS December 31, 2001 2000 (in thousands)
$2,758,160 957,336 900,921 233,005 74,299 4,923, 721 2,436,972 2,486,749 834,109 215,544 127,977 16,804 46,309 60,864 31,908 25,398 (741) 28,989 91,440 399,195 2,072 6,497 708,735 408,927 34,967 REGULATORY ASSETS DEFERRED CHARGES TOTAL
$2,708,436 945,709 863,736 257,152 96,440 4,871,473 2,280 521 2,590,952 778,720 194,554 131,417 14,835 106,832 48,706 27,491 (759) 16,532 84,471 1,222,925
-6,066 1,527,099 552,140 36,156 See Notes to Financial Statements beginning on page L-1.
F-8
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES 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 Advances from Affiliates Accounts Payable -
General Accounts Payable - Affiliated Companies Taxes Accrued Interest Accrued obligations under capital Leases Energy Trading and Derivative Contracts Other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVESTMENT TAX CREDITS DEFERRED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 LONG-TERM ENERGY TRADING CONTRACTS DEFERRED CREDITS December 31, 2001 2000 (in thousands) 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 90,817 43,956 69,761 20,691 10,840 383,714 72,435 1,032,214 400,531 105,449 77,592 175,581 92,039 56,584 733,072 3,443 793,099 8,736 64,945 1,298,939 2,165,719 560,628 108,600 669,228 90,000 253,582 119,472 75,486 68,416 21,639 100,848 1,267,981 97,070 2,094,494 487,945 113,773 81,299 156,343 42,237 COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL See Notes to Financial Statements beginning on page L-1.
F-9
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2001 OPERATING ACTIVITIES:
Net Income (Loss)
Adjustments for Noncash Items:
Depreciation and Amortization Amortization of Incremental Nuclear Refueling Outage Expenses (net)
Amortization (Deferral) of Nuclear Outage Costs (net)
Deferred Federal Income Taxes Deferred Investment Tax Credits Mark-to-Market of Energy Trading Contracts unrecovered Fuel and Purchased Power costs changes in Certain Current Assets And Liabilities:
Accounts Receivable (net)
Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payab1e Taxes Accrued 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 Buyout of Nuclear Fuel Leases other Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES:
Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt change in Advances from Affiliates (net) change in Short-term Debt (net)
Dividends Paid on common stock Dividends Paid on cumulative Preferred stock Net Cash Flows From (Used For)
Financing Activities Net Increase (Decrease) in cash and cash Equivalents cash and cash Equivalents January 1 cash and cash Equivalents December 31 75,788 166,360 418 40,000 (29,205)
(8,324)
(19,502) 37,501 64,841 (19,426)
(2,072)
(60,185) 1,345 (5,871)
(5,461) 236,207 (91,052)
(92,616) 1,074 182, 594) 297,656 (44,922)
(299,891)
(4,487) 51, 644) 1,969 14,835 2O000 (in thousands)
(132,032) 163,391 5,737 40,000 (125,179)
(7,854)
(10,859) 37,501 (25,305) 10,743 44,428 85,056 19,446 56,856 (68,160) 37 668 131 437 (171,071) 587 (170,484) 199,220 (314)
(148,000) 253,582 (224,262)
(26,290)
(3,368) 50,568 11,521 3,314
!4_ 8 3 5 1999 32,776 153,921 8,480 (160,000) 85,727 (8,152)
(2,602)
(84,696)
(19,178)
(12,880)
(7,151) 19,068 13,809 (3,228)
(48,879) 63,763 30,778 (165,331) 2,501 (162,830) 247,989 (3,597)
(109,500) 115,562 (114,656)
(5,856) 129,942 (2,110) 5,424 3.314 Supplemental Disclosure:
Cas paid (received) for interest net of capitalized
$78,703,000 and for income taxes was $100,470,000, 2000 and 1999, respectively.
Noncash acquisitions
$22,218,000 and $10,852,000 in 2001, 2000 and 1999, amounts was $92,140,000,$82,511,000 and
$73,254,000 and $(71,395,000) in
- 2001, under capital leases were $1,023,000, respectively.
See Notes to Financial Statements beginning on page L-1.
F-I 0
[II
INDIANA MICHIGAN POWER COMPANY AND Consolidated Statements of Retained Earnin0s Retained Earnings january 1 Net Income (LOSS)
Deductions:
cash Dividends Declared:
Common Stock cumulative Preferred stock:
4-1/8% Series 4.56% series 4.12% series 5.90% series 6-1/4% series 6.30% series 6-7/8% series Total Cash Dividends Declared capital stock Expense Total Deductions SUBSIDIARIES Year Ended December 31, 2001 2000 1999 (in thousands) 3,443
$ 166,389
$253,154 75,788 (132,032) 32.776 79,231 34,357 285,930 229 66 72 897 1,203 834 1,186 4,487 139 4,626 26,290 230 66 74 897 1,203 834 1,186 30,780 134 30,914 114,656 244 66 78 963 1,250 834 1,238 119,329 212 119.541 Retained Earnings December 31 a I See Notes to Financial statements beginning on page L-1.
F-11
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, 2001 2000 (in thousands)
COMMON SHAREHOLDER'S EQUITY 860,570 793,099 PREFERRED STOCK:
$100 Par value Authorized 2,250,000 shares
$25 Par Value Authorized 11,200,000 shares Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31. 2001 2001 2000 1999 Not subject to Mandatory Redemption:
4-1/8%
106.125 3,750 97 55,389 5,539 5,539 4.56%
102 150 14,412 1,441 1,441 4.12%
102.728 1,375 17,556 1,756 1,756 8,736 8,736 Subject to Mandatory Redemption:
5.90% (a,b) 15,000 152,000 15,200 15,200 6-1/4% (a,b) 10,000 192,500 19,250 19,250 6.30% (a,b) 132,450 13,245 13,245 6-7/8% (a,c) 10,000 172,500 17,250 17,250 64,945 64,945 LONG-TERM DEBT (See schedule of Long-term Debt):
First Mortgage Bonds 264,141 308,976 Installment Purchase Contracts 310,239 309,717 Senior unsecured Notes 696,144 397,435 Other Long term Debt 219,947 211,307 Junior De entures 161,611 161,504 Less Portion Due within One Year (340,000)
(90,000)
Long-term Debt Excluding Portion Due within One Year 1,312,082 1,298,939 TOTAL CAPITALIZATION UIU413 (a) Not callable until after 2002.
There are no aggregate sinking fund provisions through 2002.
Sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares each year in 2004, 2005 and 2006.
The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date.
(b)
Commencing in 2004 and continuing through 2008 the company may redeem, at $100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009.
Shares previously redeemed may be applied to meet the sinking fund requirement.
(c) 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.
shares previously redeemed may be applied to meet the sinking fund requirement.
See Notes to Financial Statements beginning on page L-1.
F-12
. I.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows:
December 31, 2001 2000 (in thousands)
% Rate Due 7.63 2001 7.60 2002 7.70 2002 6.10 2003 8.50 2022 7.35 2023 7.20 2024 7.50 2024 unamortized June 1 November 1 50,000 December 15 40,000 November 1 30,000
- December 15 75,000
- october 1 15,000 February 1 30,000 March 1 25,000 Discount (859)
$ 40,000 50,000 40,000 30,000 75,000 20,000 30,000 25,000 (1,024)
First mortgage bonds are secured by first mortgage liens on electric utility plant.
Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:
December 31, 2001 2000 (in thousands)
% Rate Due city of Lawrenceburg, Indiana:
7.00 2015 - April 1
$ 25,000 5.90 2019 -
November 1 52,000 ci ty (a) 7.60 6.55 (b) of Rockport, Indiana:
2014 - August 1 2016 -
March 1 2025 -
June 1 2025 -
June 1 50,000 40,000 50,000 50,000
$ 25,000 52,000 50,000 40,000 50,000 50,000 The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. On the variable rate series the principal is payable at the stated maturities or on the demand of the bondholders at periodic interest adjustment dates which occur weekly. The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002.
Accordingly, the variable rate installment purchase contracts have been classified for repayment purposes based on the expiration date of the letter of credit.
Senior unsecured notes outstanding were as follows:
December 31, 2001 2000 (in thousands)
% Rate Due (a) 2002 -
September 3 $200,000
$200,000 6-7/8 2004 -
July 1 150,000 150,000 6.125 2006 -
December 15 300,000 6.45 2008 -
November 10 50,000 50,000 unamortized Discount (3,856)
(2,565) 1A32Z4 (a) A floating interest rate is determined quarterly.
The rate on December 31, 2001 and 2000 was 2.71%
and 7.31%,
respectively.
The average interest rate was 5.1% in 2001 and 7.3% in 2000.
city of Sullivan, Indiana:
5.95 2009 -
May 1 45,000 45,000 unamortized Discount (1.761)
(2,283)
(a) A variable interest rate is determined weekly.
The average weighted interest rate was 2.4% for 2001 and 4.5% for 2000.
(b) In June 2001 an auction rate was established.
Auction rates are determined by standard procedures every 35 days.
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 from 2.9% to 5.9% in 2000 and averaged 3.3% during 2001 and 4.2% during 2000.
F-13
Junior debentures outstanding were as follows:
At December 31, 2001, future annual long-term debt payments are as follows:
December 31, 2001 2000 (in thousands)
% Rate Due 8.00 2026 - March 31 $ 40,000 7.60 2038 - June 30 125,000 Unamortized Discount C3,389)
Total
$ 40,000 125,000 (3,496)
SI11504 Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.
2002 2003 2004 2005 2006 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) 340,000 30,000 150,000 300,000 841,947 1,661,947 (9,865)
$1,65W__
F-I4
. 1
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Financial Statements The notes to I&M's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants.
Listed below are the combined notes that apply to I&M.
The combined footnotes begin on page L-1.
Significant Accounting Policies Merger Nuclear Plant Restart Effects of Regulation Customer choice and Industry Restructuring Commitments and contingencies Benefit Plans Business Segments Risk Management, Financial Instruments and Derivatives Income Taxes supplementary Information Leases Lines of Credit and sale of Receivables unaudited Quarterly Financial Information Related Party Transactions combi ned Footnote Reference Note 1
Note 3
Note 4
Note 6
Note 7
Note 8
Note 10 Note 12 Note 13 Note 14 Note 16 Note 18 Note 19 Note 20 Note 24 F-1 5
111 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 its subsidiaries as of December 31, 2001 and 2000, 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, 2001. 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 its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 F-16
NOTES TO FINANCIAL STATEMENTS The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants.
The following list of footnotes shows the registrant to which they apply:
- 1. significant Accounting Policies
- 2.
Extraordinary Items and cumulative Effect
- AEP, AEGCo,
- APCo, CPL,
- CSPCo, I&M,
- KPCo, OPCo,
- PSO, SWEPCo, WTU
- AEP, APCO,
- CPL, CSPCO,
- OPCO, SWEPCO, WTU
- 3.
Merger
- AEP, CPL, I&M,
- KPCO, PSO,
- SWEPCO, WTU
- 4. Nuclear Plant Restart
- 5. Rate Matters
- 6. Effects of Regulation
- 7.
Customer choice and Industry Restructuring
- 8. commitments and Contingencies
- 9. Acquisitions and Dispositions
- 10. Benefit Plans
- 11. Stock-Based compensation
- 12. Business Segments
- 13.
Risk Management, Financial Instruments and Derivatives
- 14.
Income Taxes
- 15. Basic and Diluted Earnings Per share
- 16. Supplementary Information
- 17.
Power, Distribution and Communications Projects
- 18. Leases
- 19. Lines of credit and sale of Receivables
- AEP, I&M
- AEP, APCo,
- SWEPCO, WTU
- AEP, AEGCO,
- APCO, CPL,
- CSPCO, I&M,
- KPCO, OPCO,
- PSO, SWEPCO, WTU
- AEP, APCO,
- CPL, CSPCO, I&M,
- OPCO, PSO,
- SWEPCO, WTU
- AEP, AEGCO,
- APCO, CPL,
- CSPCO, I&M,
- KPCo, OPCo,
- PSO, SWEPCO, WTU
- AEP, OPCO, SWEPCO
- AEP, APCo,
- CPL, CSPCo, I&M,
- KPCo, OPCo,
- PSO, SWEPCO, WTU AEP
- AEP, AEGCO,
- APCO, CPL,
- CSPCO, I&M,
- KPCO, OPCO,
- PSO, SWEPCO, WTU
- AEP, AEGCO,
- APCO, CPL,
- CSPCo, I&M,
- KPCO, OPCo,
- PSO, SWEPCO, WTU
- AEP, AEGCo,
- APCo, CPL,
- CSPCo, I&M,
- KPCO, OPCO,
- PSO, SWEPCO, WTU AEP
- AEP, APCO,
- CSPCO, I&M, OPCO AEP
- AEP, AEGCO,
- APCO, CPL,
- CSPCO, I&M,
- KPCO, OPCo,
- PSO, SWEPCO, WTU
- AEP, AEGCO,
- APCO, CPL,
- CSPCO, I&M,
- KPCO, OPCO,
- PSO, SWEPCO, WTU L-1 I 'I
- 20. unaudited Quarterly Financial Information
- 21. Trust Preferred Securities
- 22.
Minority Interest in Finance subsidiary
- 23. Jointly Owned Electric Utility Plant
- 24. Related Party Transactions
- AEP, AEGCO,
- APCO, CPL,
- CSPCo, I&M,
- KPCO, OPCo,
- PSO, SWEPCO, WTU
- AEP, CPL,
- PSO, SWEPCO AEP
- CPL, CSPCo,
- PSO, SWEPCo, WTU
- AEGCo, APCo,
- CPL, CSPCo, I&M,
- KPCo, OPCo,
- PSO, SWEPCo, WTU L-2
[II
- 1. Significant Accounting Policies:
Business Operations - AEP's principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power.
Nine of AEP's eleven domestic electric utility operating companies, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU, are SEC registrants.
AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant.
These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions.
AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent coal, oil, natural gas liquids and emission allowances in the United States and Europe. In addition the Company's domestic operations includes non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas.
International operations include regulated supply and distribution of electricity and other non regulated power generation projects in the United Kingdom, Australia, Mexico, South America and China.
The Company also operates domestic barging, provides energy services worldwide and furnishes communications related services domestically.
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 the UK, Australia, 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, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo 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 by APCo in June 2000, in Texas by CPL, WTU, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 7,
"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.
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 domestic operations and other investments are stated at their fair market value at acquisition plus L-3
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 overheads incurred to operate and maintain plant are included in operating expenses.
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 2001, 2000 and 1999 were not significant.
Effective with the discontinuance of the application of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia and West Virginia and for 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 2001, 2000, and 1999.
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-Nucl ear Steam-Fossil -Fi red Hydroelectric-conventional and Pumped storage Transmi ssion Di stri buti on other Functional Class of Property Production:
Steam-Nucl ear Steam-Fossil-Fired Hydroelectric-conventional and Pumped Storage Transmission Distribution Other Functional class of Propertv Production:
Steam-Nuclear Steam-Fossil-Fired Hydroelectric-Conventional and Pumped storage Transmi ssi on Distribution Other 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%
Annual Composite Dep reci ati on Rates Ranýes 1999 2.8% to 3.4%
3.2% to 5.0%
1.9% to 1.7% to 2.8% to 2.0% to 3.4%
2.7%
4.2%
20.0%
The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2001, 2000 and 1999 which were as follows:
Nuclear Steam Hydro Transmission Distribution General AEGCO APCo CPL CSPCO I&M KPCo OPCo PSO SWEPCo WTU 2.5 3.4 3.5%
3.4 2.5 3.2 4.5 3.8 3.4 2.7 3.4 2.8 2.9 1.9 3.4 2.7 2.2 2.3 2.3 1.9 1.7 2.3 2.3 2.7 3.1 3.3 3.5 3.6 4.2 3.5 4.0 3.4 3.6 3.3 2.8%
3.1 4.0 3.2 3.8 2.5 2.7 6.0 4.5 6.6 L-4
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 at a current average rate of
$3.46 per ton in 2001, $5.07 per ton in 2000 and
$2.32 per ton in 1999. These costs are included in the cost of coal charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Inventory - Except for CPL, PSO and WTU, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. CPL, PSO and WTU, 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.
Natural gas inventories are marked-to-market if held in connection with trading operations. Any non-trading gas inventory is carried at the lower of cost or market.
Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts receivable for the domestic utility subsidiaries and 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 companies balances sheet. See Note 19 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 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 Statement of Cash Flows in "Effect of Exchange Rate Change 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 under fuel clauses for AEP was $139 million at December 31, 2001 and $407 million at December 31, 2000. See also Note 6 "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 currently. 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 5, "Rate Matters" and Note 7, "Customer Choice and Industry Restructuring" for further information about fuel recovery.
Revenue Recognition - We recognize revenues from foreign and domestic generation, transmission and distribution of electricity, domestic gas pipeline and storage services, other energy supply related business activities, as well L-5
as domestic barging, telecommunications and related services. The revenues associated with these activities are recorded when earned as physical commodities are delivered to contractual meter points or services are provided.
These revenues also include the accrual of earned, but unbilled and/or not yet metered revenues. Such revenues are based on contract prices or tariffs and presented on a gross basis consistent with generally accepted accounting principles and industry practice. Revenue recognition for energy marketing and trading transactions is further discussed within the Energy Marketing and Trading Transactions section below.
The Company follows EITF 98-10 and marks to market energy trading activities, which includes the net change in fair value of open trading contracts in earnings. Mark-to-market gains and losses on open contracts and net settlements of financial contracts (see below) are included in revenues on a net basis.
The net basis of reporting for open contracts is permitted by EITF 98-10 and for settled financial contracts is consistent with industry practice. Settled physical forward trading transactions are reported on a gross basis, as permitted by EITF 98-10.
Management believes that the gross basis of reporting for settled physical forward trading contracts is a better indication of the scope and significance of energy trading activities to the Company.
Energy Marketing and Trading Transactions AEP engages in wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities inolve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the counter options and swaps.
Although trading contracts are generally short-term, there are long term trading contracts.
The majority of trading activities represent forward electricity and gas contracts that are typically settled by entering into offsetting physical contracts.
Forward trading sale contracts are included in AEP's revenues when the contracts settle. Forward trading purchase contracts are included in AEP's fuel and purchased energy expenses when they settle. Prior to settlement the change in fair values of forward sale and purchase contracts are included in AEP's revenues.
All of the registrant subsidiaries except AEGCo participate in AEP's wholesale marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo record forward electricity trading sale contracts in operating revenues when the contracts settle for contracts with delivery points in AEP's traditional marketing area and in nonoperating income for forward electricity trading sale contracts outside AEP's traditional marketing area.
APCo, CSPCo, I&M, KPCo and OPCo record forward electricity trading purchase contracts in purchased power expense when the contracts settle for contracts with delivery points in AEP's traditional marketing area and in nonoperating expense for forward electricity trading purchase contracts outside AEP's traditional marketing area. CPL, PSO, SWEPCo and WTU record revenues from forward electricity trading sale contracts in operating revenues.
CPL, PSO, SWEPCo and WTU record purchased power expense for forward electricity trading purchase contracts when they settle.
APCo, CSPCo and OPCo account for open forward electricity sale and purchase contracts on a mark-to-market basis and include the mark-to market change in operating revenues for open contracts in AEP's traditional marketing area and in nonoperating income for open contracts beyond AEP's traditional marketing area.
I&M and KPCo account for open forward electricity sale and purchase contracts on a mark to-market basis and defer the mark-to-market change as regulatory assets or liabilities for those open contracts in AEP's traditional marketing area and include the mark-to-market change in nonoperating income for open contracts beyond AEP's traditional marketing area.
CPL, PSO, SWEPCo and WTU account for open forward electricity sale and purchase contracts on a mark-to-market basis. CPL includes the mark to-market change for open electricity trading contracts in revenues. PSO defers as regulatory assets or liabilities the mark-to-market change for open forward electricity trading contracts that are included in cost of service on a settlement basis L-6
for ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the mark-to market change in revenues for open electricity trading contracts for those jurisdictions that are not subject to SFAS 71 cost based rate regulation and defer as regulatory assets or liabilities the jurisdictional share of the mark-to-market change for open contracts that are included in cost of service on a settlement basis for ratemaking purposes.
Trading purchases and sales through electricity and gas options, futures and swaps, represent financial transactions with the net proceeds reported in AEP's revenues at fair value upon entering the contracts.
APCo, CSPCo, I&M, KPCo and OPCo share in AEP's trading sales and purchases through electricity options, futures and swaps, which represent financial transactions. Changes in fair values of these financial contracts are reported net in nonoperating income.
When these contracts settle, the net proceeds are recorded in nonoperating income and the prior unrealized gain or loss in reversed.
Recording of the net changes in fair value of open trading contracts is commonly referred to a mark to-market accounting.
All open contracts from trading activities are marked to market in accordance with EITF 98-10.
Except as noted above, the net mark-to-market (change in fair value) amount included in results of operations on a net discounted basis. 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 valuation models produce an extimated fair value for open long-term trading contracts.
The short-term and long-term fair values are present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices.
Bid/ask price curves are developed for inclusion in the model based on broker quotes and other available market data.
The curves are within the range between the bid and ask price. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid side of the bid ask if we have a long position and the ask side if we have a short position. This provides for a conservative valuation net of the reserves. 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 risks, at the time of settlement, do not correlate with AEP developed price models.
The effect on AEP's Consolidated Statements of Income of marking to market open electricity trading contracts in AEP's regulated jurisdictions is deferred as regulatory assets or liabilities 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.
Hedging and Related Activities -
In order to mitigate the risks of market price and interest rate fluctuations, AEP's foreign subsidiaries, SEEBOARD and CitiPower, utilize interest swaps, and currency swaps to hedge such market fluctuations.
Changes in the market value of these swaps are deferred until the gain or loss is realized on the underlying hedged asset, liability or commodity.
To qualify as a hedge, these transactions must be designated as a hedge and changes in their fair value must correlate with changes in the price and interest rate movement of the underlying asset, liability or commodity.
This in effect reduces AEP's exposure to the effects of market fluctuations related to price and interest rates.
AEP, APCo, CSPCo, I&M, 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 L-7 "C-'-.
N.',
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, 2001 or 2000. See Note 13 -
"Risk Management, Financial Instruments and Derivatives" for further discussion of the accounting for risk management transactions.
Levelization of Nuclear Refueling Outage Costs In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M's Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.
Maintenance Costs -
Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost based regulated revenues.
See below for an explanation of costs deferred in connection with an extended outage at I&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 in 2001, 2000 and 1999 leaving $80 million as an SFAS 71 regulatory asset at December 31, 2001 on the Consolidated Balance Sheets of AEP and I&M.
Other Income and Other Expenses -
Other Income includes equity earnings of non consolidated subsidiaries, gains on dispositions of property, interest and dividends, an allowance for equity funds used during construction (explained above) and various other non-operating and miscellaneous income. Other Expenses includes losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses.
Income Taxes - The AEP System follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax consequence.
Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity),
deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense.
Investment Tax Credits - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment.
Excise Taxes -
AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity.
Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement.
Debt and Preferred Stock - Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plant are generally deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment. If debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the term of the replacement debt commensurate with L-8
[II
their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to SFAS 71 are reported as a component of net income.
Debt discount or premium and debt issuance expenses are deferred and amortized over the term of the related debt, with the amortization included in interest charges.
Where rates are regulated redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistent with the timing of its inclusion in rates in accordance with SFAS 71.
Goodwill and Intangible Assets - The amount of acquisition cost in excess of the fair value allocated to tangible and identifiable intangible assets obtained through an acquisition accounted for as a purchase combination is recorded as goodwill on AEP's consolidated balance sheet.
Goodwill recognized in connection with purchase combinations acquired after June 30, 2001 was determined in accordance with SFAS 141 "Business Combinations."
(see also Note 9, "Acquisitions and Dispositions").
For goodwill associated with purchase combinations before July 1, 2001, amortization is on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which is being amortized on a
straight-line basis over 10 years.
Accumulated amortization of goodwill was $199 million and $166 million at December 31, 2001 and 2000, respectively. In accordance with SFAS 142, "Goodwill and Other Intangible Assets,"
goodwill acquired after June 30, 2001 is not subject to amortization.
The amortization of goodwill which predates July 1, 2001 ceased on December 31, 2001.
SFAS 142 requires that other intangible assets be separately identified and if they have finite lives they must be amortized over that life.
Other intangible assets of
$441 million net of accumulated amortization of $38 million at December 31, 2001 are included in other assets and represent retail and wholesale distribution licenses for CitiPower operating franchises which are currently being amortized on a straight-line basis over 20 and 40 years, respectively.
Also SFAS 142 provides that goodwill and other intangible assets with indefinite lives be tested for impairment annually and not be subjected to amortization. For AEP's goodwill recognized prior to July 1, 2001 and other intangible assets, these requirements will apply beginning January 1, 2002. For the year 2001, the amortization of goodwill reduced AEP's net income by $50 million.
AEP is still evaluating the impact of adopting the impairment tests required by SFAS 142.
Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities.
By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers' funds and to allow those funds to earn a reasonable return. In general, limitations include:
"* Acceptable investments (rated investment grade or above)
"* Maximum percentage invested in a specific type of investment
"* Prohibition of investment in obligations of the applicable company or its affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities.
The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives.
Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and L-9
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 - Comprehensive income 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 owners and distributions to owners.
Comprehensive income has two components, net income and other comprehensive income. There were no material differences between net income and comprehensive income for AEGCo, CPL, CSPCo, PSO, SWEPCo and WTU.
Components of Other Comprehensive Income Other comprehensive income is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income for AEP.
Foreign Currency Adjustments unrealized Losses On Securities unrealized Gain on Hedged Derivatives Minimum Pension Liability December 31, 2001 2000 1999 (millions)
$(113)
$ (99)
$ 20 (20)
(3)
__ 0)
( )
(4)
Accumulated Other Comprehensive Income for AEP registrant subsidiaries as of December 31, 2001, is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income for the two years ended December 31, 2000 and 1999 were zero.
Di Components
(
Foreign Currency Rate Hedge APCo I&M KPCO OPCo ecember 31, 2001 thousands)
$ (340)
(3,835)
(1,903)
(196)
Segment Reporting -
The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business segment as viewed by the chief operating decision-maker.
See Note 12 "Business Segments" for further discussion and details regarding segments.
Common Stock Options -
AEP follows Accounting Principles Board Opinion 25 to account for stock options. Compensation expense is not recognized at the date of grant or when exercised, because the exercise price of stock options awarded under the stock option plan equals the market price of the underlying stock on the date of grant.
EPS -
AEP's basic earnings per share is determined based upon the weighted average number of common shares outstanding during the years presented. Diluted earnings per share for AEP is based upon the weighted average number of common shares and stock options outstanding during the years presented. Basic and diluted EPS are the same in 2001, 2000 and 1999.
AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU are wholly-owned subsidiaries of AEP and are not required to report EPS.
Reclassification - Certain prior year financial statement items have been reclassified to conform to current year presentation. Such reclassification had no impact on previously reported net income.
Certain settled forward energy transactions of the trading operation were reclassified from a net to a gross basis of presentation in order to better reflect the scope and nature of the AEP System's energy sales and purchases.
All financially net settled trading transactions, such as swaps, futures, and unexercised options, and all marked-to-market values on open trading contracts continue to be reported on a net basis, reflecting the financial nature of these transactions. As applicable, prior year amounts of realized physical purchases from L-1 0 SI I
settled purchase trading contracts were reclassified from revenues to purchased power expense to present the prior period on a comparable gross basis.
- 2. Extraordinary Items and Cumulative Effect:
Extraordinary Items - Extraordinary items were recorded for the discontinuance of regulatory accounting under SFAS 71 for the generation portion of the business in the Ohio, Virginia, West Virginia, Texas and Arkansas state jurisdictions.
See Note 7 "Customer Choice and Industry Restructuring" for descriptions of the restructuring plans and related accounting effects. OPCo and CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax GRT) net of allowable Ohio coal credits during the quarter ended June 30, 2001. This loss resulted from regulatory decisions in connection with Ohio deregulation which stranded the recovery of the GRT. Effective with the liability affixing on May 1,
- 2001, CSPCo and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies have appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the Ohio companies believe failed to provide for recovery for the final year of the GRT. The Ohio Supreme Court decision is expected in 2002.
In October 2001 CPL reacquired $101 million of pollution control bonds in advance of their maturity.
Since these pollution control bonds were used to finance generation assets, a loss of
$2 million after tax was recorded.
The following table shows the components of the extraordinary items reported on the consolidated statements of income:
Extraordinary Items:
Discontinuance of Regulatory Accounting for Generation:
Ohio jurisdiction (Net of Tax of $20 million in 2001 and
$35 Million in 2000) virginia and west virginia Jurisdictions (Inclusive of Tax Benefit of $8 Million)
Texas and Arkansas jurisdictions (Net of Tax of $5 Million)
LOSS on Reacquired Debt (Net of Tax of $1 Million in 2001 and $3 Million in 1999)
Extraordinary Items Year Ended December 31, 2001 2000 1999 (in millions)
$(48) $(44) 9 (8)
__(2) __ _- g(6)
Cumulative Effect of Accounting Change - 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 electricity capacity contracts can qualify as a normal purchase or sale.
Predominantly all of AEP's fuel supply contracts for coal and gas and contracts for electricity capacity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument or qualify as a normal purchase or sale. Therefore, AEP's contracts are generally exempt from the DIG guidance described above. Beginning July 1, 2001, the effective date of the DIG guidance, certain of AEP's fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. The effect of initially adopting the DIG guidance at July 1, 2001, for AEP is a favorable earnings mark-to market effect of $18 million, net of tax of $2 million, is reported as a cumulative effect of an accounting change on the income statement.
- 3. Merger:
On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP.
Under the terms of the merger agreement, approximately 127.9 million shares of AEP Common Stock were issued in exchange for all the outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share of AEP Common Stock for each share of CSW Common Stock. Following the exchange, former shareholders of AEP owned approximately 61.4 percent of the corporation, while former CSW shareholders owned approximately 38.6 percent of the corporation.
The merger was accounted for as a pooling of interests.
Accordingly, AEP's consolidated financial statements give retroactive effect to the merger, with all periods presented as if AEP and CSW had always been combined.
Certain reclassifications have been made to conform the historical financial statement presentation of AEP and CSW.
The following table sets forth
- revenues, extraordinary items and net income previously reported by AEP and CSW and the combined amounts shown in the accompanying financial statements for 1999:
Revenues:
AEP CSW AEP After Pooling Extraordinary Items:
AEP CSW AEP After Pooling Net Income:
AEP CSW conforming Adjustment AEP After Pooling Year Ended December 31, 1999 (in millions)
$19,229 5,516
(
- 14)
_LA)
$520 455 (3)
_$=/
The following table shows the vacation accrual conforming adjustment for CSW's registrant utility subsidiaries:
CPL PSO SWEPCo WTU Net Income Reductions Net Asset Year Ended Reduction at December 31, December 31, 1999 1999 (in millions)
$5.3
$0.7 2.8 1.1 4.5 0.5 2.6 0.4 In connection with the merger, $21 million ($14 million after tax) and $203 million ($180 million after tax) of non-recoverable merger costs were expensed in 2001 and 2000. Such cost included transaction and transition costs not recoverable from ratepayers.
Also included in the merger costs were non-recoverable change in control payments.
Merger transaction and transition costs of $51 million recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements through December 31, 2001. 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 and $4 million for the years 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:
Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2000 December 31, 2000 (in millions)
$14.4 6.9 2.5 7.9 6.1 4.2
$1.3 0.7 0.3 0.5 0.5 0.4 The combined financial statements include an adjustment to conform CSW's accounting for vacation pay accruals with AEP's accounting. The effect of the conforming adjustment was to reduce net assets by $16 million at December 31, 1999 and reduce net income by $3 million for the year ended December 31, 1999.
CPL I&M KPCo PSO SWEPCo WTU Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2001 December 31, 2001 (in millions)
$11.8
$2.6 9.1 1.7 3.2 0.6 6.6 1.2 5.0 1.1 3.5 0.8 L-1 2
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 -
SWEPCo Louisiana SWEPCo provisions of Merger Rate Ratemakinq 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 of $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.
The current annual dividend rate per share of AEP common stock is $2.40. The dividends per share reported on the statements of income for 2000 and 1999 represent pro forma amounts and are based on AEP's historical annual dividend rate of $2.40 per share. If the dividends per share reported for prior periods were based on the sum of the historical dividends declared by AEP and CSW, the annual dividend rate would be $2.60 per combined share for the year ended December 31, 1999.
See Note 8, "Commitments and Contingencies" for information on a recent court decision concerning the merger.
- 4. 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 I&M under licenses granted by the NRC.
I&M shut down both units of the Cook Plant in September 1997 due to questions regarding the operability of certain safety systems that arose during a NRC architect engineer design inspection.
Settlement agreements in the Indiana and Michigan retail jurisdictions that address recovery of Cook Plant related outage costs were approved in 1999. The IURC approved a settlement agreement that resolved all matters related to the recovery of replacement energy fuel costs and all outage/restart costs and related issues during the extended outage of the Cook Plant. The MPSC approved a settlement agreement for two open Michigan power supply cost recovery reconciliation cases that resolved all issues related to the Cook Plant extended outage. The settlement agreements allowed:
"* deferral of $200 million of non-fuel restart related nuclear operation and maintenance expense for amortization over five years ending December 31, 2003,
"* deferral of certain unrecovered fuel and power supply costs for amortization over five years ending December 31, 2003,
"* a freeze in base rates through December 31, 2003 and a fixed fuel recovery charge through March 1, 2004 in the Indiana jurisdiction, and
"* a freeze in base rates and fixed power supply costs recovery factors until January 1, 2004 for the Michigan jurisdiction.
L-1 3
FE(qC Transmission Rates - In November 2001 FERt. issued an order requiring CPL, PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and calculate and issue refunds for overcharges from January 1, 1997. The order resulted from a remand by an appeals court of a tariff compliance filing order issued in November 1998 that had been appealed by certain customers. CPL and WTU recorded refund provisions of $1.7 million and $0.7 million, respectively, including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each for this order making the AEP total $2.6 million.
West Virginia - On June 2, 2000, the WVPSC approved a Joint Stipulation between APCo and other parties related to base rates and ENEC recoveries.
The Joint Stipulation allows for recovery of regulatory assets including any generation-related regulatory assets through the following provisions:
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 million 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 (see Note 7 "Customer Choice and Industry Restructuring" for discussion of the WV Restructuring Plan)
Management expects that the approved Joint Stipulation, plus the provisions of pending restructuring legislation will, if the legislation becomes effective, provide for the recovery of existing regulatory assets, other stranded costs and the cost of deregulation in WV.
- 6. Effects of Regulation:
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 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 Company's business in Arkansas, Ohio, Texas, Virginia and WV 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 WV 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. As discussed in Note 7, "Customer Choice and Industry Restructing" 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. In the Texas jurisdiction generation-related regulatory assets that have been tentatively approved for recovery through securitization have been classified as "regulatory assets designated for securitization." (See Note 7 "Customer Choice and Industry Restructuring" for further details.)
L-1 6
-1
AEP's recognized regulatory assets and liabilities are comprised of the following at:
Regulatory Assets:
Amounts Due From Customers For Future Income Taxes Transition -
Regulatory Assets Regulatory Assets Designated for securitization Deferred Fuel costs unamortized Loss on Reacquired Debt cook Plant Restart Costs DOE Decontamination and Decommissioning Assessment other Total Regulatory Assets Regulatory Liabilities:
Deferred Investment Tax credits other Total Regulatory Liabilities December 31, 2001 2000 (in millions) 814 847 959 139 99 80 31 193 53-16BZ 914 963 953 407 113 120 35 193
$491
$528 393 208 SH M-6 L-17
[II The recognized regulatory assets and liabilities for the registrant subsidiaries are of two types: those earning a return and those not earning a return. Items not earning a return have their recovery period end date indicated. Regulatory assets and liabilities are comprised of the following items:
AEGCo APCo Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)
Regulatory Assets:
Amounts Due From Customers For Future Income Taxes
$(22,725) $(23,996)
Note 1
$189,794 $217,540 Note 1 Transition -
Regulatory Assets Virginia 46,981 55,523 3un.
2007 Transition -
Regulatory Assets west Virginia 127,998 135,946 Jun. 2011 Deferred Fuel costs 11,732 14,669 Unamortized Loss on Reacquired Debt 5,207 5,504 Note 2 10,421 11,676 Note 2 Deferred Storm Damage 6
1,244 Apr.
2002 other 71,890 11,152 Note 3 Total Regulatory Assets
$_-172*_2
_447,_S4ZA Regulatory Liabilities:
Deferred Investment Tax Credits
$56,304
$59,718
$ 38,328 $ 43,093 WV Rate Stabilization 75,601 75,601 other 61,552 2 614 Total Regulatory Liabilities S 56 9110A 1.ZL:II 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-seven years recovery period across all registrants.
Note 3: other may include items not earning a return and would have various recovery periods.
CPL CSPCo Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)
Regulatory Assets:
Amounts Due From Customers For Future Income Taxes
$200,496 $
206,930 Note 1
$ 28,361 $ 31,853 Note 1 Transition -
Regulatory Assets 223,830 247,852 Dec.
2008 Excess Earnings (62,852)
(39,700)
Regulatory Assets Designated For Securitization 959,294 953,249 Deferred Fuel costs (57,762) 127,295 unamortized Loss on Reacquired Debt 11,180 12,773 Note 2 7,010 8,340 Note 2 DOE Decontamination and Decommissioning Assessment 3,170 3,622 Dec. 2004 Other 11,961 18,815 Note 3 3,066 3,508 Note 3 Total Regulatory Assets
$1-L* 65.j7
]
M =294 Ufa Regulatory Liabilities:
Deferred Investment Tax credits
$122,893
$128,100
$37,176
$41,234 other 31 11J510 Total Regulatory Liabilities
$1289.
$]2J.*
$9 2$ZIf 52 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-seven years recovery period across all registrants.
Note 3: Other may include items not earning a return and would have various recovery periods.
I&M KPCo Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)
Regulatory Assets:
Amounts Due From Customers For Future Income Taxes
$171,605
$229,466 Note 1
$83,027
$85,926 Note 1 Deferred Fuel Costs 75,002 112,503 Dec.
2003 1,542 Feb.
2002 unamortized LOSS on Reacquired Debt 16,255 17,740 Note 2 51 459 Note 2 Cook Plant Restart Costs 80,000 120,000 Dec. 2003 DOE Decontamination and Decommissioning Assessment 27,784 31,744 Dec. 2008 other 38 281 40.687 Note 3 13.073 12,130 Note 3 Total Regulatory Assets Regulatory Liabilities:
Deferred Investment Tax credits
$105,449
$113,773
$10,405
$11,656 other 52,479 9,930 65.51 3,172 Total Regulatory Liabilities 3157.92 E
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-seven years recovery period across all registrants.
Note 3: other may include items not earning a return and would have various recovery periods.
OPCo PSO Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)
Regulatory Assets:
Amounts Due From Customers For Future Income Taxes
$186,740
$180,602 Note 1
$(26,085)
$(28,652)
Note 1 Transition -
Regulatory Assets 442,707 517,851 Dec. 2007 Deferred Fuel Costs 11,732 43,267 unamortized Loss on Reacquired Debt 5,502 6,106 Note 2 12,321 13,600 Note 2 other 9 676 10,151 Note 3 11.707 15,738 Note 3 Total Regulatory Assets
$644.625-714,710$
- 9.
Regulatory Liabilities:
Deferred Investment Tax credits
$21,925
$25,214
$33,992
$35,783 other 1,237 1
31.858 2,015 Total Regulatory Liabilities 3
1 Note 1: This amount fluctuates from month to month and has no fixed recovery period.
Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants.
Note 3: other may include items not earning a return and would have various recovery periods.
SWEPCo WTU Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)
Regulatory Assets:
Amounts Due From Customers For Future Income Taxes
$16,553
$14,558 Note 1
$(13,591)$(13,493)
Note 1 Deferred Fuel Costs 7,384 35,469 36,872 67,655 unamortized Loss on Reacquired Debt 19,726 22,626 Note 2 8,198 11,204 Note 2 other 15.711 A19898 Note 3 5,460 13,604 Note 3 Total Regulatory Assets 5
Regulatory Liabilities:
Deferred Investment Tax credits
$48,714
$53,167
$22,781
$24,052 Excess Earnings 500 17,300 15,100 Other 15,454 8,140 I,10 Total Regulatory Liabilities S
6 L
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-seven years recovery period across all registrants.
Note 3: other may include items not earning a return and would have various recovery periods.
- 7. Customer Choice and Industry Restructuring:
Prior to 2001 customer choice/industry restructuring legislation was passed in Ohio, Texas, Virginia and Michigan allowing retail customers to select alternative generation suppliers. Customer choice began on January 1, 2001 in Ohio and on January 1,2002 in Michigan, Virginia and in the ERCOT area of Texas. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.
Legislation enacted in Oklahoma, Arkansas and WV to allow retail customers to choose their electricity supplier is not yet effective.
In 2001 Oklahoma delayed implementation of customer choice indefinitely. Arkansas delayed the start of customer choice until as late as October 2005.
The Arkansas Commission has recommended further delays of the start date or repeal of the restructuring legislation. Before West Virginia's choice plan can be effective, tax legislation must be passed to continue consistent funding for state and local government. No further legislation has been passed related to restructuring in Arkansas or 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. During 2001 alternative suppliers registered and were approved by the PUCO as required by the Ohio Act. At January 1, 2002, 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 provides 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, approval of a transition plan for each electric utility company and addressed certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs.
The Ohio Act made several changes in the taxation of electric companies. Effective January 1, 2001 the assessment percentage for property taxes on all electric company property other than transmission and distribution was lowered from 100% to 25%.
The assessment percentage applicable to transmission and distribution property remains at 88%.
- Also, electric companies were exempted from the excise tax based on receipts. To make up for these tax reductions electric distribution companies became subject to a new KWH based excise tax. Since electric companies no longer paid the gross receipts tax, they became liable, as of January 1, 2002 for the corporation franchise tax and municipal income taxes.
In preparation for the January 1, 2001 start of the transition period, CSPCo and OPCo filed a transition plan in December 1999.
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, 2000, the amount of regulatory assets to be amortized as recovered was $518 million for OPCo and $248 million for CSPCo.
The stipulation agreement required the PUCO to consider implementation of a gross receipts tax credit rider as the parties could not reach an agreement.
L-20 1[I
As of 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 will pay the excise tax based on gross receipts is 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 treat the tax payment as a prepaid expense and amortized it to expense during the tax year.
Following a hearing on the gross receipts tax issue, the PUCO determined that there was no duplicate tax overlap period. 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. This order reduced CSPCo's and OPCo's revenues by approximately $90 million.
CSPCo's and OPCo's request for rehearing of the gross receipts tax issue was also denied by the PUCO. A decision on an appeal of this issue to the Ohio Supreme Court is pending.
As described in Note 2, the PUCO's denial of the request for recovery of the final year's gross receipts tax and the tax liability affixing on May 1, 2001 stranded the prepaid asset. As a result, an extraordinary loss was recorded in 2001.
One of the intervenors at the hearings for approval of the settlement agreement (whose request for rehearing was denied by the PUCO) filed with the Ohio Supreme Court for review of the settlement agreement.
During 2001 that intervenor withdrew from competing in Ohio. The Court dismissed the intervenor's appeal.
CSPCo's and OPCo's fuel costs were no longer subject to PUCO fuel clause recovery proceedings beginning January 1, 2001.
The elimination of fuel clause recoveries in Ohio subjects AEP, CSPCo and OPCo to risk of fuel market price variations and could adversely affect their results of operations and cash flows.
Virginia Restructuring - Affecting AEP and APCo In Virginia, choice of electricity supplier for retail customers began on January 1, 2002 under its restructuring law. A finding by the Virginia SCC that an effective competitive market exists would be required to end the transition period.
The restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for net stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate change request was made by the utility. APCo did not request new rates; therefore, its current rates are its capped rates.
Virginia's restructuring law does not permit the Virginia SCC to change generation rates during the transition period except for changes in fuel costs, changes in state gross receipts taxes, or to address financial distress of the utility.
The Virginia restructuring law also requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC. The Virginia SCC approved settlement agreements that resolved most issues except the assignment of generation-related regulatory assets among functionally separated generation, transmission and distribution organizations. The Virginia SCC determined that generation-related regulatory assets and related amortization expense should 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 will not collect a wires charge in 2002 per the settlement agreements.
The settlement agreements and related Virginia SCC order addressed functional separation leaving decisions related to corporate separation for later consideration. The Virginia SCC order approving the settlement agreements requires several compliance filings, including a fuel/replacement power cost report during an extended outage of an affiliate's nuclear plant.
Management is unable to predict the outcome of the Virginia SCC's review of APCo's compliance filings.
Texas Restructuring -
Affecting AEP, CPL.
SWEPCo and WTU 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 WTU's service territory are located in the SPP. CPL 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; freezes rates until January 1, 2002; provides for an earnings test for each of the three years of the rate freeze period (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; provides for elimination of the fuel clause reconciliation process beginning January 1, 2002; and provides for a 2004 true-up proceeding to determine recovery of stranded costs including final fuel recovery balances, net regulatory
- assets, certain environmental costs, accumulated excess earnings and other issues.
Under the Texas Legislation, delivery of electricity continues to be the responsibility of the local electric transmission and distribution utility company at regulated prices. Each electric utility was required to submit a plan to structurally unbundle its business activities into a retail electric provider, a power generation company, and a transmission and distribution utility. In 2000 CPL, SWEPCo and WTU filed and the PUCT approved business separation plans.
The business separation plans provided for CPL and WTU to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. In February 2002 the PUCT approved amendments to SWEPCo's plan. The amended plan separates SWEPCo's Texas jurisdictional transmission and distribution assets and operations into two new regulated transmission and distribution subsidiaries. In addition, a retail electric provider was established by SWEPCo to provide retail electric service to SWEPCo's Texas jurisdictional customers. Until competition commences in the SPP, SWEPCo's assets will not be separated and the SWEPCo retail electric provider will not commence operation.
Due to the SPP area delay in the start of competition, only CPL's and WTU's retail electric providers commenced operations on January 1, 2002. Operations for CPL, SWEPCo and WTU have been functionally separated.
Under the Texas Legislation, electric utilities are allowed to recover stranded generation costs including generation-related regulatory assets.
The stranded costs can be refinanced through securitization (a financing structure designed to provide lower financing costs than are available through conventional financings).
In 1999 CPL filed with the PUCT to securitize
$1.27 billion of its retail generation-related regulatory assets and $47 million in other qualified restructuring costs.
The PUCT authorized the issuance of up to $797 million of securitization bonds ($949 million of generation related regulatory assets and $33 million of qualified refinancing costs offset by $185 million of customer benefits for accumulated deferred income taxes).
Four parties appealed to the Supreme Court of Texas which upheld the PUCT's securitization order. CPL issued its securitization bonds in February 2002.
CPL included regulatory assets not approved for securitization in its request for recovery of $1.1 billion of stranded costs. The $1.1 billion request included $800 million of STP costs included in property, plant and equipment-electric on the L-22
[II
Consolidated Balance Sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes. They are earning a lower return and being amortized on an accelerated basis for rate making purposes.
After hearings on the issue of stranded costs, the PUCT ruled in October 2001 that its current estimate of CPL's stranded costs was negative
$615 million. CPL disagrees with the ruling. The ruling indicated that CPL's costs were below market after securitization of regulatory assets.
Management believes CPL has a positive stranded cost exclusive of securitized regulatory assets. The final amount of CPL's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding.
If CPL's total stranded costs determined in the 2004 true-up are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of regulatory costs authorized by the PUCT to be securitized. However, 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 CPL to reduce distribution rates by $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. The Texas Legislation intended that excess earnings reduce stranded costs.
Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings.
Since CPL expensed excess earnings amounts 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 CPL will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time.
CPL has appealed the PUCT's estimate of stranded costs and refund of excess earnings to the Travis County District Court.
Unaffiliated parties also appealed the PUCT's refund order contending the entire $615 million of negative stranded costs should be refunded presently. Management is unable to predict the outcome of this litigation. An unfavorable ruling would have a negative impact on results of operations, cash flows and possibly financial condition.
The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, the issuance of power generation company stock to the public or the use of an ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the additional amount recoverable can also be securitized.
The Texas Legislation provides for an earnings test each year of the 1999 through 2001 rate freeze period. For CPL, any earnings in excess of the most recently approved cost of capital in its last rate case must be applied to reduce stranded costs. Companies without stranded
- costs, including SWEPCo and WTU, must pay any excess earnings to customers, invest them in improvements to transmission or distribution facilities or invest them to improve air quality at generating facilities.
The Texas Legislation requires PUCT approval of the annual earnings test calculation.
The PUCT issued a final order for the 1999 earnings test in February 2001 and adjustments to the accrued 1999 and 2000 excess earnings were recorded in results of operations in the fourth quarter of 2000. After adjustments the 1999 excess earnings for CPL and WTU were $24 million and $1 million, respectively. SWEPCo had no excess earnings in 1999. The PUCT issued a final order in September 2001 for the 2000 excess earnings. CPL's, SWEPCo's and WTU's excess 2000 earnings were $23 million, $1 million and
$17 million, respectively. An estimate of 2001 excess earnings of $8 million for CPL, $2 million for SWEPCo and none for WTU has been L-23
recorded and will be adjusted, if necessary, in 2002 when the PUCT issues its final order regarding 2001 excess earnings.
Due to the companies' disagreement with the PUCT, its staff and the Office of Public Utility Counsel related to the proper determination of 2000 excess earnings, the companies filed in district court in October 2001 seeking judicial review of the PUCT's determination of excess earnings.
A decision from the court is not expected until later in 2002.
Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel reconciliation proceedings for CPL and WTU's ERCOT customers.
Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001.
Due to the delay of competition for the SPP area, SWEPCo, which operates in the SPP area, continues to record and request recovery of fuel costs under the Texas fuel reconciliation proceeding. For WTU's SPP area customers, the PUCT will determine a method to reconcile their fuel costs beginning in 2002 (see Note 5 "Rate Matters").
Final unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled are not recovered, they could have a negative impact on results of operations.
The elimination of the fuel clause recoveries in 2002 in the ERCOT area of Texas will subject AEP and the retail electric providers of CPL and WTU to greater risks of fuel market price increases and could adversely affect future results of operations beginning in 2002.
The affiliated retail electric providers of CPL, SWEPCo and WTU are required by the Texas Legislation to offer residential and small commercial customers (with a peak usage of less than 1000 KW) a price-to-beat rate until January 1, 2007. In December 2001 the PUCT approved price-to-beat rates for CPL's and WTU's retail electric providers. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas restructuring legislation provides for the price to beat to be adjusted up to two times annually to reflect changes in fuel and purchased energy costs using a natural gas price index.
Due to the delay in the start of competition in the SPP areas of Texas, several issues are pending before the PUCT.
These issues impact SWEPCo's and WTU's Texas SPP operations.
WTU's Texas SPP operations are estimated to be less than 5% of WTU's total operations.
West Virginia Restructuring - Affecting AEP and APCo In 2000 the WVPSC issued an order approving an electricity restructuring plan which the WV Legislature approved by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes tax law changes necessary to preserve the revenues of state and local governments. Since the WV Legislature has not passed the required tax law changes, the restructuring plan has not become effective. AEP subsidiaries, APCo and WPCo, provide electric service in WV.
The WV restructuring plan provides for:
"* deregulation of generation assets
"* separation of the generation, transmission and distribution businesses
"* a transition period with capped and fixed rates for up to 13 years
"* establishment of a rate stabilization deferred liability balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end of year ten of the transition period.
APCo's Joint Stipulation, discussed in Note 5 "Rate Matters" and approved by the WVPSC in 2000 in connection with a base rate filing, provides additional mechanisms to recover transition generation-related regulatory assets.
In order for customer choice to become effective in WV, the WV Legislature must enact tax legislation. Management is unable to predict the timing of the passage of such legislation.
Arkansas Restructuring -
Affecting AEP and SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry.
Major provisions of the legislation as amended are:
retail competition delayed until as late as October 2005; L-24
transmission facilities must be operated by an ISO if owned by a company which also owns generating facilities; rates will be frozen for one to three years; market power issues will be addressed by the Arkansas Commission; and an annual progress report to the Arkansas General Assembly on the development of competition in electric markets and its impact on retail customers is required.
Based on recommendations in the annual progress report filed by the Arkansas Commission, the Arkansas General Assembly passed and the Governor signed legislation in 2001 changing the start date of electric retail competition to October 1, 2003, and providing the Arkansas Commission with authority to delay that date for up to an additional two years.
The Arkansas Commission in December 2001 recommended further delays of the start date or repeal of the restructuring legislation.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas, Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CPL, CSPCo, OPCo, SWEPCo and WTU 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 enabled AEP and certain subsidiaries to discontinue 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 in accordance with the provisions of SFAS 101 and EITF Issue 97-4 resulted in recognition of extraordinary gains or losses in 2000 and 1999. 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.
Prior to 1999, all of the domestic electric utility subsidiaries' financial statements reflected the economic effects of regulation under the requirements of SFAS 71.
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 Company 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 results of operations, cash flows and possibly financial condition.
Michigan Restructuring - Affecting AEP and I&M On June 5, 2000, the Michigan Legislation became law. Its major provisions, which were effective immediately, applied only to electric utilities with one million or more retail customers.
I&M, AEP's electric operating subsidiary doing business in Michigan, has less than one million customers in Michigan. Consequently, I&M was not immediately required to comply with the Michigan Legislation.
The Michigan Legislation gives the MPSC broad power to issue orders to implement retail customer choice of electric supplier no later than January 1, 2002 including recovery of regulatory assets and stranded costs. In compliance with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access tariffs and terms of service. On October 11, 2001, the L-25
MPSC approved a settlement agreement which generally approved I&M's June 5, 2001 filing except for agreed upon modifications.
In accordance with the settlement agreement, I&M agreed that recovery of implementation costs and regulatory assets would be determined in future proceedings. The settlement agreement did not modify the procedure for review of decom missioning costs recoveries. Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers.
l&M's total rates in Michigan remain unchanged and reflect cost of service. At this time, none of I&M's customers have elected to change suppliers and no competing suppliers are active in I&M's Michigan service territory.
Management has concluded that as of December 31, 2001 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated. As a result I&M has not yet dis continued regulatory accounting under SFAS 71.
Oklahoma Restructuring - Affecting AEP and PSO Under Oklahoma restructuring legislation passed in 1997 retail open access and customer choice was scheduled to begin by July 1, 2002.
In June 2001 the Oklahoma Governor signed into law a bill to delay, indefinitely, the implementation of the transition to customer choice and market based pricing under restructuring legislation.
Consequently, PS0, the AEP subsidiary doing business in Oklahoma, will remain rate-regulated until further legislation passes and continues the application of SFAS 71 regulatory accounting.
- 8. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2002-2004 for consolidated domestic and foreign operations are estimated to be $5.4 billion.
The following table shows the estimated construction expenditures of the subsidiary registrants for 2002 - 2004:
(in millions)
AEGCo APco CPL CSPCO I&M KPCO OPco PSO SWEPCo WTU
$ 171.9 815.5 573.1 408.7 556.9 223. 3 1,008.0 364.9 321.4 169.6 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. Through December 31, 2001 we had invested approximately $40 million in this effort.
If the required regulatory approvals are not obtained and the line is not constructed, the $40 million investment would be written off adversely affecting future results of operations and cash flows.
Long-term contracts to acquire fuel for electric generation have been entered into for various terms, the longest of which extends to the year 2014 for the AEP System. The expiration date of the longest fuel contract is 2006 for APCo, 2005 for CSPCo, 2014 for I&M, 2004 for KPCo, 2012 for OPCo, 2014 for PSO, 2006 for SWEPCo and 2006 for WTU. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,300 MW of capacity domestically on a long-term basis to unaffiliated utilities.
Certain of these contracts totaling 250 MW of capacity are unit power agreements requiring the delivery of energy only if the unit capacity is available. The power sales contracts expire from 2002 to 2012.
In connection with a lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the obligations of the mining contractor.
The contractor's actual obligation outstanding at L-26
December 31, 2001 was $75 million.
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite
- mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of
$85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At December 31, 2001 the cost to reclaim the mine is estimated to be approximately
$36 million.
AEP, through certain subsidiaries, has entered into agreements with an unrelated, unconsolidated special purpose entity (SPE) to develop, construct, finance and lease a power generation facility. The SPE will own the power generation facility and lease it to an AEP consolidated subsidiary after construction is completed. The lease will be accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to an unrelated industrial company which will both use the energy produced by the facility and sell excess energy. Another affiliate of AEP has agreed to purchase the excess energy from the subleasee for resale.
The SPE has an aggregate financing commitment from equity and debt participants (Investors) of
$427 million.
AEP, in its role as construction agent for the SPE, is responsible for completing construction by December 31, 2003. In the event the project is terminated before completion of construction, AEP has the option to either purchase the project for 100% of project costs or terminate the project and make a payment to the Lessor for 89.9% of project costs.
The term of the operating lease between the SPE and the AEP subsidiary is five years with multiple extension options. If all extension options are exercised the total term of the lease would be 30 years. AEP's lease payments to the SPE are sufficient to provide a return to the Investors. At the end of the first five-year lease term or any extension, AEP may renew the lease at fair market value subject to Investor approval; purchase the facility at its original construction cost; or sell the facility, on behalf of the SPE, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Investors, AEP may be required to make a payment to the Lessor of up to 85% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to the SPE during the construction and post-construction periods.
As of December 31, 2001, project costs subject to these agreements totaled $168 million, and total costs for the completed facility are expected to be approximately $450 million. Since the lease is accounted for as an operating lease for financial accounting purposes, neither the facility nor the related obligations are reported on AEP's balance sheets. The lease 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 under the first five-year lease term calculated using the indexed LIBOR rate of 2.85% at December 31, 2001.
OPCo has entered into a purchased power agreement to purchase electricity produced by an unaffiliated entity's three-unit natural gas fired plant that is under construction. The first unit is anticipated to be completed in October 2002 and the agreement will terminate 30 years after the third unit begins operation. Under the terms of the agreement OPCo has the options to run the plant until December 31, 2005 taking 100% of the power generated. 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 through December 2005 are $55 million.
Nuclear Plants - Affecting AEP, CPL and I&M I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC.
CPL owns 25.2% of the two-unit 2,500 MW STP.
STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special L-27
risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial.
By agreement I&M and CPL are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations, cash flows and financial condition would be adversely affected.
Nuclear Incident Liability - Affecting AEP, CPL and I&M The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $9.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $88 million on each licensed reactor in the U.S. payable in annual installments of $10 million.
As a result, I&M could be assessed $176 million per nuclear incident payable in annual installments of $20 million. CPL could be assessed $44 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment.
The number of incidents for which payments could be required is not limited.
Insurance coverage for property
- damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess coverage for property damage, de commissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage.
I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage.
Participation in this mutual insurer requires a contingent financial obligation of up to
$36 million for I&M and $3 million for CPL which is assessable if the insurer's financial resources would be inadequate to pay for losses.
SNF Disposal - Affecting AEP, CPL, and I&M Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal.
A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $220 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt.
I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.
At December 31,
- 2001, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and approximate the liability. CPL is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989.
Decommissioning and Low Level Waste Accumulation Disposal-Affecting AEP, CPL and
/&M Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. After expiration of the licenses, Cook Plant is expected to be decommissioned through dismantlement.
The estimated cost of decommissioning 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 re covering 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 L-28 I I
2001 and $28 million in 2000 and 1999.
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 decontamination method. CPL estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL 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 2001 and 2000 I&M deposited in its decommissioning trust an additional $12 million and $6 million, respectively, 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 CPL's balance sheets, the nuclear decommissioning liability of
$99 million is included in electric utility plant accumulated depreciation and amortization. At December 31, 2001 and
- 2000, the decommissioning liability for Cook Plant and STP combined totals $699 million and $654 million, respectively.
Shareholders' Litigation - Affecting AEP On December 21, 2001, the U.S. District Court for the Southern District of Ohio dismissed a class action lawsuit against AEP and four former or present officers.
The class consisted of all persons and entities who purchased or otherwise acquired AEP common stock between July 25, 1997 and June 25, 1999. The complaint alleged that the defendants knowingly violated federal securities laws by disseminating materially false and misleading statements related to the extended Cook Plant outage.
Municipal Franchise Fee Litigation - Affecting AEP and CPL In 2001 CPL settled litigation regarding municipal franchise fees in Texas. CPL paid $11 million to settle the litigation and be released from any further liability. The City of San Juan, Texas had filed a class action suit in 1996 seeking $300 million in damages.
Texas Base Rate Litigation - Affecting AEP and CPL In 2001 the Texas Supreme Court denied CPL's request to review a case resulting from a 1997 PUCT base rate order. The Court also denied CPL's rehearing request.
The primary issues were:
the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; and an $18 million disallowance of an affiliate service billings.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In 2001 SWEPCo settled ongoing litigation concerning lignite mining in Louisiana.
Since 1997 SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine operator's interest in the mining operations and related debt and other obligations for $86 million.
Federal EPA Complaint and Notice of Violation Affecting AEP, APCo, CSPCo, I&M, and OPCo Since 1999 AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding L-29
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 Court for the 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 March 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.
In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense.
In January 2002 the U.S. Court of Appeals for the 1 1 th Circuit ruled that TVA may pursue its court challenge of a Federal EPA administrative order charging similar violations to those in the complaints against AEP and other utilities.
Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C.
Beckjord Generating Station Unit 6 (owned 25.4%
and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its results of operations and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located.
The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004.
The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans.
Those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. AEP subsidiaries and other utilities requested that the D.C. Circuit Court review this ruling.
In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act.
The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal fired generating units. Affected utilities including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date.
On August 24, 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand.
Federal EPA has announced that it intends to adopt May 31, 2004, as the compliance date for the Section 126 Rule when it finalizes the NOx budgets for both rules.
In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo.
The compliance date is May 2003 for CPL and May 2005 for SWEPCo.
During 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant commenced operations. Construction of SCR technology at certain other AEP generating units continues with completion scheduled in 2002 through 2006.
Our estimates indicate that compliance with the NOx
- Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion of which approximately $450 million has been spent through December 31, 2001 for the AEP System.
Estimated compliance costs and amounts spent by registrant subsidiaries are as follows:
AEGCo APCO CPL CSPCo I&M KPCo OPCO SWEPCO Estimated Amount Compliance Cost Spent (in millions)
$125 365 130 57 4
106 1
202 140 13 606 277 28 21 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary 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-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 court told 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 explain its conclusions that the transmission 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 At the 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 from Enron and entered into a lease arrangement with a subsidiary of Enron for a gas storage facility. At the date of Enron's bankruptcy various HPL related contingencies and indemnities remained unsettled.
In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy.
The amounts for certain subsidiary registrants were:
Regi strant Amounts Provided (in
$5.2 3.2 3.4 1.3 4.3 Amounts Net of Tax millions)
$3.4 2.1 2.2 0.8 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceedings, our future results of operations, cash flows and possibly financial condition could be adversely impacted.
Other - AEP and its registrant 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.
- 9. Acquisitions and Dispositions:
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 as determined by the Company's management based on information currently available and on current assumptions as to future operations.
Based on a preliminary purchase price allocation the excess of cost over fair value of the net assets acquired was approximately
$190 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.
SFAS 141 "Business Combinations" apply to all business combinations initiated and consummated after June 30, 2001.
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 including existing mine reclamation liabilities at its jointly owned lignite reserves in Louisiana.
The purchase resulted from a litigation settlement discussed in Note 8,
"Commitments and Contingencies".
Management expects the acquisition to have minimal impact on results of operations.
Quaker Coal Company as part of a bankruptcy proceeding settlement and assumed additional liabilities of approximately $58 million. The acquisition L-32 APCO CSPCO I&M KPCO OPCo
includes property, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will continue to operate the mines and facilities which employ over 800 individuals.
MEMCO Barge Line that adds 1,200 hopper barges and 30 towboats to AEP's existing barging fleet.
MEMCO's 450 employees will continue to operate the barge line.
MEMCO also adds major barging operations on the Mississippi and Ohio rivers to AEP's barging operations on the Ohio and Kanawha rivers.
4,000 megawatts of UK coal-fired generation that includes 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.
A 20% equity interest in Caiua, a Brazilian electric operating company which is a subsidiary of Vale. See Note 17, "Power, Distribution and Communications Projects". The Company converted a total of $66 million on an existing loan and accrued interest on that loan into Caiua equity.
Indian Mesa Wind Project consisting of 160 megawatts of wind generation located near Fort Stockton, Texas.
Acquired existing contracts and hired 22 key staff from Enron's London-based international coal trading group.
Regarding the 2001 acquisitions management has recorded the assets acquired 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. Management is in the process of obtaining independent appraisals regarding certain of these acquisitions and evaluating others to refine its determination of fair values.
Accordingly the allocation of the purchase prices are subject to revision based on the final determinations.
Dispositions In March 2001 CSWE, a subsidiary company, completed the sale of Frontera, a generating plant that the FERC required to be divested in connection with the merger of AEP and CSW.
The sale proceeds were $265 million and resulted in an after tax gain of $46 million.
In July 2001 AEP, through a wholly owned subsidiary, sold its 50% interest in a 120 megawatt generating plant located in Mexico.
The sale resulted in an after tax gain of approximately $11 million.
In July 2001 OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008.
The sale is expected to have a nominal impact on results of operations and cash flows.
In December 2001 AEP completed the sale of its ownership interests in the Virginia and West Virginia PCS (personal communications services)
Alliances for stock.
AEP recorded a 25%
valuation provision on the stock received and is restricted from selling this stock until after January 1, 2003. In addition, the number of shares AEP can sell each month is limited in order to prevent large swings in the stock price. The sales resulted in an after tax gain of approximately $7 million.
In December 2000 the Company, 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 impairment 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 quarter of 2001. The impairment writedown is included in Other Income on AEP's Consolidated Statements of Income. On February 26, 2001 an agreement to sell the Company's 50% interest in Yorkshire was signed.
On April 2, 2001, following the approval of the buyer's shareholders, the sale was completed without further impact on AEP's consolidated earnings.
In December 2000, CSW International, a
subsidiary company sold its investment in a L-33
Chilean electric company for $67 million. A net loss on the sale of $13 million ($9 million after tax) is included in Other Income, and includes $26 million ($17 million net of tax) of losses from foreign exchange rate changes that were previously reflected in other comprehensive income. In the second quarter of 2000 manage ment determined that the then existing decline in market value of the shares was other than temporary. As a result the investment was written down by $33 million ($21 million after tax) in June 2000. The total loss from both the write down of the Chilean investment to market in the second quarter and from the sale in the fourth quarter was $46 million ($30 million net of tax).
- 10. Benefit Plans:
In the U.S. AEP sponsors two qualified pension plans and two nonqualified pension plans.
Substantially all employees in the U.S., are covered by one or both of the pension plans.
OPEB plans are sponsored by the AEP System to provide medical and death benefits for retired employees in the U.S.
The foreign pension plans are for employees of SEEBOARD in the U.K.
and CitiPower in Australia.
The majority of SEEBOARD's employees joined a
pension plan that is administered for the U.K.'s electricity industry. The assets of this plan are actuarially valued every three years. SEEBOARD and its participating employees both contribute to the plan.
Subsequent to July 1, 1995, new employees were no longer able to participate in that plan and two new pension plans were made available to new employees of SEEBOARD. CitiPower sponsors a defined benefit pension plan that covers all employees.
The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending December 31, 2001, and a statement of the funded status as of December 31 for both years:
[II
U.S.
Pension Plans 2001 2000 Foreign Pension Plans 2001 2000 (in millions)
U.S.
OPEB Plans 2001 2000 Reconciliation of benefit obligation:
obligation at January 1$
Service Cost Interest Cost Parti ci pant Contributions Plan Amendments Foreign Currency Translation Adjustment Actuarial (Gain) Loss Divestures Benefit Payments Curtailments obligation at December 31 Reconciliation of fair value of plan assets:
Fair value of plan assets at January 1 Actual Return on Plan Assets Company Contributions Parti ci pant Contributions Foreign Currency Translation Adjustment Benefit Payments Fair value of plan assets at December 31 Funded status:
Funded status at December 31 Unrecognized Net Transition (Asset) obligation unrecognized Prior-Service cost unrecognized Actuarial (Gain)
Loss Prepaid Benefit (Accrued Liability)
(a) one of the qualified pensio pay 3,161 69 232 121 (291) 3,911 (182)
(291)
$146 (15)
(12) 35 nMpA n plans
$2,934 60 227 (71) (a) 218 (207)
$3,866 250 2
(207)
$ 750 (23)
(12)
(628) 5__8U converted to
$1,179 12 60 4
(36)
(62)
(58)
$1, 290 (131) 7 4
(40)
$(27) 9 74 5-56
$1,176 13 64 5
(95) 80 (64)
$1,405 55 5
(111)
(6.249
$1,668 30 114 8
17 192 (287)
(88) 1
$704 (31) 118 8
(88)
$111
$(944) 263 10 17 649
$1,365 29 106 7
(b)
(67)
(c) 262 (d)
(85) 51 (e)
$668 2
112 7
(85)
$(964) 298 448 191)
I_5A the cash balance pension formula from a final average formula.
(b) Related to the purchase of Houston Pipe Line company and MEMCO Barge Line.
(c) change to a service-related formula for retirement health care costs and a 50% of pay life insurance benefit for retiree life insurance.
(d) Related to the sale of central Ohio Coal Company, Southern Ohio coal Company and windsor coal company.
(e) Related to the shutdown of Central Ohio coal Company, southern Ohio Coal company and windsor Coal company.
The following table provides the amounts for prepaid benefit costs and accrued benefit liability recognized in the consolidated balance sheets as of December 31 of both years. The amounts for additional minimum liability, intangible asset and accumulated other comprehensive income for 2000 were recorded in 2001 and the amounts for 2001 will be recorded in 2002.
U.S.
Pension Plan 2001 2000 Foreign Pension Plans 2001 200U (in millions)
U. S.
OPEB Plans 2001 2000 Prepaid Benefit Costs Accrued Benefit Liability Additional Minimum Liability Intangible Asset Accumulated other Comprehensive Income Net Asset (Liability) other comprehensive (Income)
Expense Attributable to change in Additional Pension Liability Recognition N/A = Not Applicable
$ 205 (51)
(15) 9 6
i_0)
$ 159 (72)
(24) 14 10
$8__7
$57 (1)
$54 1
(16)
N/A N/A N/A L-35 3
(221)
N/A N/A N/A
I[I Both of the AEP System's nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $40 million and $26 million at December 31, 2001 and $41 million and $26 million at December 31, 2000. There are no plan assets in the nonqualified plans.
The AEP System's OPEB plans had accumulated benefit obligations in excess of plan assets of $944 million and $964 million at December 31, 2001 and 2000, respectively.
In late December 2001 AEP purchased generation plants in the UK (see Note 9, "Acquisitions and Dispositions"). The purchase included the pension plan of the existing generation plant employees. In connection with the acquisition, a $10 million liability for the accumulated benefit obligation in excess of plan assets was assumed.
The following table provides the components of AEP's net periodic benefit cost for the plans for fiscal years 2001, 2000 and 1999:
Service cost Interest cost Expected return on plan assets Amortization of transition (asset) obligation Amortization of prior-service cost Amortization of net actuarial (gain) loss Net periodic benefit cost (credit) curtailment loss(a)
Net periodic benefit cost (credit) after curtailments U.S.
Pension Plans 2001 2000 1999 69 232 (338) 60 227 (321) 71 211 (299)
Foreign Pension Plans 2001 2000 1999 (in millions)
$ 12
$ 13
$ 15 60 64 59 (69)
(75)
(71)
(8)
(8)
(8) 13 12 C24)
- 39) 15)
(69)
(68)
U.S.
OPEB Plans 2001 2000 1999
$ 30 114 (61)
$ 29 106 (57)
$ 33 90 (49) 30 41 43 18 4
5 (28) 4 3
3 131 123 122 1
79 18 k(69) &_(W) 5_(Z8)
$4 3
$_ 1132
$202
$-14-0 (a) curtailment charges were recognized during 2000 and 1999 for the shutdown of Central Ohio coal company, Southern Ohio coal company and windsor Coal company.
The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999:
U.S.
U.S Pension Plans OPEB Plans 2001 2000 1999 2001 2000 1999 (in thousands)
APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU
$(13,645)
(3,411)
(10,624)
(7,805)
(1,922)
(14,879)
(2,480)
(3,051)
(1,664)
$(14,047)
(2,986)
(10,905)
(8,565)
(2,075)
(15,041)
(2,196)
(2,606)
(1,585)
$(3,925)
(4,270)
(4,893)
(1,259)
(393)
(4,979)
(3,129)
(3,734)
(2,221)
$22,810 8,214 10,328 15,077 2,438 34,444 6,187 6,399 3,729
$ 22,139 6,656 9,643 14,155 2,364 116,205 4,277 4,152 2,929
$19,431 7,595 8,623 13,664 2,652 52,518 5,516 4,913 3,377 The weighted-average assumptions as of December 31, used in the measurement of the Company's benefit obligations are shown in the following tables:
U.S.
Foreign Pension Plans Pension Plans U.S.
OPEB Plans 2001 2000 1999 2001 2000 1999 2001 2000 1999
% u 75 80
- 5.
Discount rate 7.2S 7.50 8.00 5-5.8 5-5.5 5.5-6 7.25 7.50 8.00 plan assets Rate of compensation increase 9.00 9.00 3.7 3.2 9.00 6.1-7.5 3.8 6-7.5 6.5-7.5 4.0 3.5-4.0 4-4.5 8.75 8.75 8.75 N/A N/A N/A L-36
For OPEB measurement purposes, an 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2002. The rate was assumed to decrease gradually each year to a rate of 5% through 2005 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 I % change in assumed health care cost trend rates would have the following effects:
1% Increase (in millions)
Effect on total service and interest cost components of net periodic postretirement health care benefit cost
$ 18 Effect on the health care component of the Accumulated Postretirement Benefit obligation 189 1% Decrease
$(15)
(156)
AEP Savings Plans - The AEP Savings Plans are defined contribution plans offered to non-UMWA U.S. employees. The cost for contributions to these plans totaled $55 million in 2001, $37 million in 2000 and $36 million in 1999.
Beginning in 2001 AEP's contributions to the plans increased to 4.5% of the initial 6% of employee pay contributed from the previous 3%
of the initial 6%
of employee base pay contributed.
The following table provides the cost for contributions to the savings plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999:
2001 2000 (in thousands)
APCO CPL CSPCO I&M KPCO OPCO PSO SWEPCO WTU
$7,031 3,046 2,789 7,833 1,016 6,398 2,235 2,776 1,558
$3,988 3,161 1,638 4,231 544 3,713 2,306 2,880 1,708 1999
$4,091 3,284 1,679 3,996 561 3,744 2,435 2,961 1,766 Other UMWA Benefits - AEP and OPCo provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements.
The benefits are administered by UMWA trustees and contributions are made to their trust funds.
Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2001, 2000 and 1999.
- 11. Stock-Based Compensation:
AEP has a Long-term Incentive Plan under which a maximum of 15,700,000 shares of common stock can be issued to key employees. The plan was adopted in 2000.
Under the plan, the exercise price of each option granted equals the market price of AEP's common stock on the date of grant.
These options will vest in equal increments, annually, over a three-year period with a maximum exercise term of ten years.
CSW maintained a stock option plan prior to the merger with AEP in 2000.
Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio.
The provisions of the CSW stock option plan will continue in effect until all options expire or there are no longer options outstanding. Under the CSW stock option plan, the option exercise price was equal to the stock's market price on the date of grant. The grant vested over three years, one third on each of the first three anniversary dates of the grant, and expires 10 years after the original grant date. All CSW stock options are fully vested.
The following table summarizes share activity in the above plans, and the weighted-average exercise price:
outstanding at beginning of year Granted Exercised Forfeited outstanding at end of year options Exercisable at end of year 2001 weighted Average options Exercise (in thousands) Price 6,610 645 (216)
(217) 6,822 3_95
$36
$45
$38
$37
$37
$43 2000 wei ghted Average options Exercise (in thousands) Price 825 6,046 (26)
(235)
$40
$36
$36
$39 i*_1_0
$36 588
$41 1999 weighted Average Options Exercise (in thousands) Price 866
$40 (22)
$38
_(19)
$43 825
$40 707
$42 The weighted-average grant-date fair value of options granted in 2001 and 2000 was $8.01 and
$5.50 per share. There were no options granted in 1999.
Shares outstanding under the stock option plan have exercise prices ranging from $35 to $49 and a weighted-average remaining contractual life of 8.5 years.
If compensation expense for stock options had been determined based on the fair value at the grant date, net income and earnings per share would have been the pro forma amounts shown below:
Pro forma net income (in millions)
Pro forma earnings per share:
Basic Diluted 2001 2000
$959
$264
$2.98
$0.82
$2.97
$0.82 1999
$972
$3.03
$3.03 The proceeds received from exercised stock options are included in common stock and paid-in capital.
The pro forma amounts are not representative of the effects on reported net income for future years.
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 options granted:
Risk Free Interest Rate Expected Life Expected volatility Expected Dividend Yield 2001 4.87%
7 years 28.40%
6.05%
2000 5.02%
7 years 24.75%
6.02%
- 12. Business Segments:
In fiscal year 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, we moved toward our goal of functionally and structurally segregating 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, Marketing and trading of electricity and gas worldwide.
Gas pipeline and storage services and other energy supply related business Energy Delivery Domestic electricity transmission Domestic electricity distribution Other Foreign electricity generation investments
° Foreign electricity distribution and supply investments Telecommunication services L-38 I
Segment results of operations for the twelve months ended December 31, 2001, 2000 and 1999 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 routine income and deductions from income.
It differs from net Energy Year wholesale Delivern income in that it does not take into account interest expense or income taxes.
EBIT is believed to be a reasonable gauge of results of operations.
By excluding interest 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 income statement.
Reconciling AEP other Adiustments consolidated millions) 2001 Revenues from:
External unaffiliated customers Transactions with other operating segments Segment EBIT Depreciation, depletion and amortization expense Total assets Investments in equity method subsidiaries Gross property additions
$55,929
$ 3,356
$ 1,972 2,708 20 1,155 1,418 986 278 597 632 154 31,459 12,455 4,541 242 414 640 844 348 (a) Reconciling adjustments for Total Assets:
Eliminate intercompany balances Corporate assets other 2000 Revenues from:
External unaffiliated customers Transactions with other operating segments Segment EBIT Depreciation, depletion and amortization expense Total assets Investments in equity method subsidiaries Gross property additions 31,437
$ 3, 1,726 1,006 559 32,216 140 493 11 14, 174
$2,095 2
750 017 358 506 188 876 7,124 724 961 319 (b)
Reconciling adjustments for Total Assets:
Eliminate intercompany balances Corporate assets other 1999 Revenues from:
External unaffiliated customers Transactions with other operating segments Segment EBIT Depreciation, depletion and amortization expense Total assets Investments in equity method subsidiaries Gross property additions 19,543 1,038 1,146 565 18,408 134 390
$3,068
$2,134 573 1,008 392 454 196 11,224 6,396 755 815 475 (c)
Reconciling adjustments for Total Assets:
Eliminate intercompany balances other L-39 (3,883)
(115)
(1, 174) (a)
$61,257 2,567 1,383 47,281 656 1,832 (1,558) 404 (20)
(1,174)
$36,706 2,059 1,250 53,350 864 1,773
$24,745 2,464 1,212 35,693 889 1,680 (2,478)
(322)
(3)
(866) (b)
(955) 93
-(4)
(866)
(1,611)
(82)
(3)
(335) (c)
(345) 10 (335)
[I Geographically our business is transacted primarily in the United States and the United Kingdom with other holdings in a small number of other counties. Results of operations by geographic area are as follows:
Geographic Areas Revenues uni ted AEP United States Kingdom Other Foreign Consolidated (in millions) 2001
$53,650
$7,201
$406
$61,257 2000 34,300 2,011 395 36,706 1999 22,694 1,705 346 24,745 Long-Lived Assets United AEP united States Kingdom Other Foreign consolidated (in millions) 2001
$21,726
$2,158
$659
$24,543 2000 20,463 1,220 710 22,393 1999 19,958 1,124 783 21,865 Of the registrant operating company subsidiaries, all of the registrant subsidiaries except AEGCo have two business segments.
The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.
Twelve Months Ended December 31, 2001 Revenues From External Segment Customers EBIT (in thousands)
Total Assets Twelve Months Ended December 31. 2000 Revenues From External Segment Customers EBIT (in thousands)
Wholesale Segment APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU Energy Delivery Segment APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU Registrant Subsidiaries Company Total APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU Total Assets
$6,404,394 2,848,545 3,816,644 4,489,215 1,528,212 5,709,689 1,939,372 2,241,444 895,235
$595,036 473,182 483,219 314,410 131,183 552,713 261,877 333,004 169,036
$6,999,430 3,321,727 4,299,863 4,803,625 1,659,395 6,262,402 2,201,249 2,574,448 1,064,271
$164,844 303,926 232,372 117,396 4,935 240,128 52,086 82,409 7,930
$213,733 109,587 130,503 111,206 54,033 118,261 79,787 107,197 33,226
$378,577 413,513 362,875 228,602 58,968 358,389 131,873 189,606 41,156
$2,855,337 2,977,504 1,987,756 3,318,919 585,847 3,156,115 907,165 1,223,334 396,147
$2,252,601 2,138,482 1,118,112 1,498,089 567,396 1,759,952 1,010,732 1,273,266 527,273
$5,107,938 5,115,986 3,105,868 4,817,008 1,153,243 4,916,067 1,917,897 2,496,600 923,420
$4,512,390 1,870,689 2,767,569 3,231,065 1,055,521 4,524,513 1,184,895 1,337,776 583,358
$574,918 478,814 398,046 311,019 121,346 467,587 245,124 344,950 176,204
$5,087,308 2,349,503 3,165,615 3,542,084 1,176,867 4,992,100 1,430,019 1,682,726 759,562
$154,525 273,650 235,860 (146,297) 22,379 289,084 54,072 27,055 13,910
$191,560 136,069 81,896 126,241 49,770 138,418 85,524 129,842 50,201
$346,085 409,719 317,756 (20,056) 72,149 427,502 139,596 156,897 64,111
$3,708,252 3,182,192 2,488,513 4,003,805 766,605 4,007,722 1,011,432 1,302,398 466,499
$2,925,472 2,285,492 1,399,789 1,807,233 742,459 2,234,835 1,126,901 1,355,558 620,912
$6,633,724 5,467,684 3,888,302 5,811,038 1,509,064 6,242,557 2,138,333 2,657,956 1,087,411 L-41
[II Twelve Months Ended December 31 1999 Revenues From External Customers Segment EBIT Total Assets (in thousands)
Wholesale Segment APCo
$3,404,987
$116,907
$2,434,110 CPL 1,032,808 267,165 2,821,449 CSPCo 2,242,459 214,312 1,798,394 A&M 2,609,307 (18,055) 3,153,344 KPCo 789,008 18,569 501,212 OPCo 3,763,711 278,415 3,002,768 PSO 493,063 56,521 721,195 SWEPCo 672,158 95,385 1,032,045 WTU 270,800 25,008 369,457 Energy Delivery Segment APCo
$565,660
$208,460
$1,920,290 CPL 449,667 133,172 2,026,401 CSPCo 389,280 93,962 1,011,596 A&M 310,880 142,973 1,423,352 KPCo 129,113 51,556 485,426 OPCo 460,182 149,906 1,674,441 PSO 256,327 74,430 803,531 SWEPCo 299,369 83,143 1,074,170 WTU 174,909 46,216 491,748 Registrant Subsidiaries Company Total APCo
$3,970,647
$325,367
$4,354,400 CPL 1,482,475 400,337 4,847,850 CSPCo 2,631,739 308,274 2,809,990 I&M 2,920,187 124,918 4,576,696 KPCo 918,121 70,125 986,638 OPCo 4,196,893 428,321 4,677,209 PSO 749,390 130,951 1,524,726 SWEPCo 971,527 178,528 2,106,215 WTU 445,709 71,224 861,205 L-42
- 13. Risk Management, Financial Instruments and Derivatives:
Risk Management We are subject to market risks in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by Chief Risk Officer. The Risk Management Committee establishes risk
- limits, approves risk
- policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels.
This committee receives daily, weekly, and monthly reports regarding compliance with
- policies, limits and procedures.
The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P.
Market Risk Oversight, and senior financial and operating managers.
The risks and related strategies that management can employ are:
Risk Price Risk Interest Rate Risk Foreign Exchange Risk Credit Risk Description Volatility in commodity prices Changes in Interest rates Fluctuations in foreign currency rates Non-performance on contracts with counterparties Strategv Trading and hedging Hedging Hedging Guarantees, Collateral 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 coal,
- oil, natural gas
- liquids, and emission allowances and as a result the Company is subject to price risk. This risk is managed by the management of the trading operations, the Company's Chief Risk Officer and the Risk Management Committee. If the risk from trading activities exceeds certain pre determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. Although we do not hedge all commodity price exposure, manage ment makes informed risk taking decisions supported by the above described risk management controls.
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) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana, Michigan and West Virginia. To the extent all fuel supply for the generating units in these states are 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 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 transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt transactions denominated in foreign currencies. We do not hedge all foreign currency exposure.
Our open trading contracts, including structured transactions, are marked-to-market 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 price and then multiplying the difference by 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.
Forwards and swaps (which are a series of forwards) are valued based on forward price curves which represent a series of projected L-43
prices at which transactions can be executed in the market.
The forward price curve includes the market's expectations for prices of a delivered commodity at that future date.
The forward price curve is developed from the market bid price, which is the highest price which traders are willing to pay for a contract, and the ask or offer price, which is the lowest price traders are willing to receive for selling a contract.
Options contracts, consisting primarily of options on forwards and spread options, are 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, and the implied volatility curve. Option prices or volatilities may be quoted in the market.
Significant estimates in valuing these contracts include forward price curves, volumes, and other volatilities.
Futures and futures options traded on futures exchanges (primarily oil and gas on Nymex) are valued at the exchange price.
Market prices utilized in valuing all forward contracts, OTC options, swaps and structured transactions represent mid-market
- price, which is the average of the bid and ask prices.
These bids and offers come from brokers, on-line exchanges such as the Intercontinental Exchange, and directly from other counterparties. These prices exist for delivery periods and locations being traded or quoted and vary by period, location and commodity.
For periods and locations that are not liquid and for which external information is not readily available, management uses the best information available to develop bid and ask prices and forward curves.
Electricity and gas markets in particular have primary trading hubs or delivery points/regions and less liquid secondary delivery points. In North American natural gas markets, the primary delivery points are generally traded from Henry Hub, Louisiana. The less liquid gas or power trading points may trade as a spread (based on transportation
- costs, constraints, etc.) from the nearest liquid trading hub. Also, some commodities trade more often and therefore are more liquid than others.
For example, peak electricity is a more liquid product than off-peak electricity.
Henry Hub gas trades in monthly blocks for up to 36 months and after that only trades in seasonal or calendar blocks.
In the near term, forward price curves for gas have a seasonal shape. They are based on market quotes beyond that.
For all these factors, the curve used for valuation is the mid-point. At times bids or offers may not be available due to market events, volatility, constraints, long-dated part of the curve, etc.
When this occurs, the Company uses its best judgment to estimate the curve values until actual values are available again. The value used will be based on various factors such as last trade price, recent price trend, product spreads, location spreads (including transportation costs), cross commodity spreads (e.g.,
heat rate conversion of gas to power), time spreads, cost of carry (e.g., cost of gas storage),
marginal production cost, cost of new entrant capacity, and alternative fuel costs. Also, an energy commodity contract's price volatility generally increases as it approaches the delivery month. Spot price volatility (e.g., daily or hourly prices) can cause contract values to change substantially as open positions settle against spot prices.
When a portion of a curve has been estimated for a period of time and market changes occur, assumptions are updated to align the company's curve to the market.
The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is based on credit ratings of counterparties and represents the risk that the counterparty to the contract will fail to perform or fail to pay amounts due 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. The liquidity reserve essentially reserves half of the difference between bids and offers for each open position, such that the wider the bid offer spread (indicating lower liquidity), the greater the reserve.
We also mark to market derivatives that are not trading contracts in accordance with generally accepted accounting principles.
L-44 I I
There may be unique models for these transactions, but the curves the company inputs into the models are the same forward curves, which are described above.
We have developed independent controls to evaluate the reasonableness of our valuation models and curves.
However, there are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. Therefore, there could be a significant favorable or adverse effect on future results of operations and cash flows if market prices at settlement differ from the price models and curves.
AEP limits credit risk by extending unsecured credit to entities based on internal ratings.
AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis.
This data, in conjunction with the ratings information, is used to determine appropriate risk parameters.
AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business.
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 is not material to financial condition at December 31, 2001. At December 31, 2001 less than 5% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets.
Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price.
The following table approximates counterparty credit quality and exposure for AEP.
- Futures, Forward and Counterparty Swap Credit Quality:
Contracts Year Ending December 31, 2001 AAA/Exchanges AA A
BBB Below Investment Grade
$ 147 140 304 932 56 Options Total (in millions) 4 7
34 23
$ 147 144 311 966 79 Total U$68 4
The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP.
We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over-the-counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission.
Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at December 31, 2001 and 2000 was $55 million and $95 million. These magin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet.
AEP and its subsidiaries can be subject to further margin requirements should related commodity prices change.
The margin deposits at December 31, 2001 for the registrants were:
(in thousands)
APCO CPL CSP I&M KPCo OPCO PSO SWEPCO WTU
$2,832 299 1,736 1,879 698 2,862 247 299 99 L-45
Financial Derivatives and Hedging In the first quarter of 2001, AEP adopted SFAS
- 133, "Accounting for Derivative Instruments and Hedging Activities,"
as amended by SFAS 137 and SFAS 138. SFAS 133 requires that entities recognize all derivatives including fair value hedges as either assets or liabilities and measure such derivatives at fair value. Changes in the fair value of derivatives are included in earnings unless designated as a cash flow hedge. This practice is commonly referred to as mark-to market accounting. Changes in the fair value of derivatives that are designated as effective cash flow hedges are included in other comprehensive income. AEP recorded a favorable transition adjustment to accumu lated 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.
The amour ts of net revenue margins (sales less purchases) in 2001, 2000, and 1999 for trading activities were:
2001 2000 1999 (in millions)
Net Revenue Margin
$609
$435
$91 The amounts of revenues recorded in 2001, 2000 and 1999 for the registrant subsidiaries were:
2001 2000 1999 (in thousands)
APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU
$78,521 15,711 51,765 36,089 12,466 65,118 (2,483) 7,897 (1,491)
$72,649 3,385 48,142 58,909 23,417 73,474 9,268 6,404 1,821
$28,970 14,800 16,147 5,563 24,389 L-46 It
III
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 Company developed price curves for open long-term trading contracts. The fair values of trading contracts at December 31 are:
2001 2000 Fair Fair value value (in millions)
(in millions)
Tradinq Assets Electric Futures and Options-NYMEX 11 Physicals 3,588 8,791 Options -
OTC 182 215 swaps 117 164 Total Trading Assets Gas Futures and Options-NYMEX 143 Physicals 238 454 options -
OTC 978 1,266 swaps 5,646 6,185 Total Trading Assets Trading Liabilities Electric Futures and Options-NYMEX Physicals (3,382)
(8,852)
Options -
OTC (101)
(133) swaps (126)
(144)
Total Trading Liabilities
)
Gas Futures and options NYMEX (92)
(81)
Physicals (80)
(419)
Options -
OTC (1,076)
(934)
Swaps (5,598)
(6,449)
Total Trading Liabilities
- )*4=i) 2001 2000 Fair Fair value value (in thousands)
(in thousands)
APCo Trading Assets Electric Futures and options-NYMEX (net)
Physicals 801,306 2,234,522 Options -
OTC 46,649 59,814 Swaps 34,578 51,470 Trading Liabilities Electric Futures and Options-NYMEX (net)
Physicals (748,016)
(2,258,596) options -
OTC (21,895)
(35,955)
Swaps (36,921)
(44,855)
KPCo Trading Assets Electric Futures and Options-NYMEX (net)
Physicals 197,545 530,828 Options -
OTC 11,503 14,207 Swaps 8,529 12,227 L-47
Trading Liabilities Electric Futures and Options-NYMEX (net)
Physicals (190,389)
Options -
OTC (5,372)
Swaps (9,106) 2001 Fai r Value (in thousands) 2000 Fai r (n
l ue (in thousands)
I&M Trading Assets Electric Futures and Options-NYMEX (net)
Physicals Options -
OTC Swaps Trading Liabilities Electric Futures and Options-NYMEX (net)
Physicals Options -
OTC Swaps OPCo Trading Assets Electric Futures and Options-NYMEX (net)
Physicals Options -
OTC Swaps Trading Liabilities Electric Futures and Options-NYMEX (net)
Physicals Options -
OTC Swaps CSPCo Trading Assets Electric Futures and Options-NYMEX (net)
Physicals options -
OTC Swaps Trading Liabilities Electric Futures and Options-NYMEX (net)
Physicals options -
OTC Swaps 560,393 31,397 22,950 (513,026)
(15,864)
(24,505) 668,142 38,108 29,730 (619,756)
(18,227)
(32,551) 491,290 28,612 21,211 (456,613)
(13,403)
(22,648) 1,349,950 36,139 31,095 (1,371,793)
(25,807)
(27,099) 1,776,259 46,731 41,788 (1,792,417)
(29,350)
(37,398) 1,192,203 31,918 27,461 (1,204,948)
(19,220)
(23,932)
L-48 (536,512)
(8,521)
(10,656)
2001 2000 Fair Fair value Value (in thousands)
(in thousands)
CPL Trading Assets Electric Physicals
$285,481
$ 542,626 Trading Liabilities Electric Physicals (281,624)
(550,817)
PSO Trading Assets Electric Physicals 217,415 431,186 Trading Liabilities Electric Physicals (214,981)
(437,694)
SWEPCo Trading Assets Electric Physicals 249,531 516,385 Trading Liabilities Electric Physicals (246,631)
(524,180)
WTU Trading Assets Electric Physicals 84,784 171,597 Trading Liabilities Electric Physicals (83,869)
(174,187)
The FASB's Derivatives Implementation Group (DIG) Issued guidance, effective in the third quarter of 2001, regarding the imple mentation of SFAS 133 for certain fuel supply contracts with volume optionality and electricity capacity contracts. The guidance 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 electricity capacity con racts can qualify as normal purchases or sales.
Predominantly all of AEP's contracts for coal, gas and electricity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument and qualify as normal purchases or sales. As a result they are exempt from the DIG guidance described above and have not been marked-to-market.
Beginning July 1, 2001, the effective date of the DIG guidance, certain of AEP's fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement.
The effect of initially adopting the DIG guidance at July 1, 2001, a favorable earnings mark-to market effect of $18 million, net of tax, is reported as a cumulative effect of an accounting change on the income statement.
Cash flows from both derivative instruments and trading activities are included in net cash flows from operating activities.
Certain derivatives may be designated for accounting purposes as a hedge of either the fair value of an asset, liability or 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 relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy for use of the hedge instrument. At the inception of the hedge and on an ongoing basis, the effectiveness of the hedge is assessed as to whether the hedge is highly effective in offsetting changes in fair value or cash flows of the item being hedged.
Changes in the fair value that result from ineffectiveness of a hedge under SFAS 133 are recognized currently in earnings through mark-to-market accounting. Changes in the fair value of effective cash flow hedges are reported in accumulated other comprehensive income if documented at inception.
Gains and losses from cash flow hedges in other comprehensive income are reclassified to earnings in the accounting periods in which the variability of cash flows of the hedged items affect earnings.
Cash flow hedges included in Accumulated Other Comprehensive income on the Balance Sheet at December 31, 2001 are:
Electric Interest Rate Foreign Currency Hedging Assets Hedging Liabilities (in millions)
$16
$ (6)
(21) other Comprehensive Income (Loss) After Tax 4
(12) 5 SLf)
The following table represents the activity in Other Comprehensive Income related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at December 31, 2001:
AEP consolidated Transition Adjustment, January 1, 2001 changes in fair value Reclasses from ocI to net income Accumulated oci derivative loss, December 31, 2001 (in millions)
$ 27 (1)
(29)
!: :!i!!
APCO Transition Adjustment, January 1, 2001 Effective portion of changes in fair value Reclasses from OCI to net income Accumulated OCI derivative gain, December 31, 2001 KPCo Transition Adjustment, January 1, 2001 Effective portion of changes in fair value Reclasses from OCT to net income Accumulated oci derivative gain, December 31, 2001 I&M Transition Adjustment, January 1, 2001 Effective portion of changes in fair value Reclasses from oCI to net income Accumulated oci derivative gain, December 31, 2001 OPCO Transition Adjustment, January 1, 2001 Effective portion of changes in fair value Reclasses from OCI to net income Accumulated oCI derivative gain, December 31, 2001 Approximately $15 million of net losses from cash flow hedges in accumulated other comprehensive income at December 31, 2001 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 5 years.
We have derivatives under SFAS 133 that do not employ hedge accounting and are not energy trading.
The derivative's mark to market value at December 31, 2001 was a
$22.7 million asset and a $13.1 million liability.
(in thousands)
(340)
(557)
(2,348) 1,002 (317)
(5,368) 1,850
$(9 (196)
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 December 31, 2001 and 2000 are summarized in the following tables.
2001 Book value Fair value (in millions)
AEP consolidated Long -term Debt
$12,053 Preferred Stock 95 Trust Preferred Securities 321 (in AEGCo Long-term Debt
$45,000 APCo Long-term Debt
$1,556,559 Preferred stock 10,860 CPL Long-term Debt
$1,253,768 Trust Preferred Securities 136,250 CSPCo Long -term Debt
$791,848 Preferred Stock 10,000 I&M Long-term Debt
$1,652,082 Preferred stock 64,945 KPCo Long-term Debt
$346,093 OPCo Long-term Debt
$1,203,841 Preferred stock 8,850 PSO Long-term Debt
$451,129 Trust Preferred Securities 75,000 SWEPCo Long-term Debt
$645,283 Trust Preferred Securities 110,000 WTU Long-term Debt
$255,967
$12,002 93 320 thousands)
$45,268
$1,439,531 10,860
$1,278,644 135,760
$802,194 10,100
$1,672,392 62,795
$350,233
$1,227,880 8,837
$462,903 74,730
$656,998 109,780
$266,846 2000 Book value Fair value (in millions)
$10,754
$10,812 100 98 334 326 (in thousands)
$45,000
$45,000
$1,6Q5,818 $1,601,313 0,860 10,725
$1,454,559
$1,463,690 148,500 147,431
$899,615
$908,620 15,000 14,892
$1,388,939
$1,377,230 64,945 63,941
$330,880
$335,408
$1,195,493.$1,176,367 8,850 8,780
$470,822
$476,964 75,000 72,180
$645,963
$651,586 110,000 106,700
$255,843
$261,315 L-52
Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The trust investments which are classified as held for sale for decommissioning and SNF disposal, reported in other assets, are recorded at market value in accordance with SFAS 115.
At December 31, 2001 and 2000 the fair values of the trust investments were $933 million and $873 million, respectively, and had a cost basis of $839 million and $768 million, respectively. The change in market value in 2001, 2000, and 1999 was a net unrealized holding loss of $11 million, and net unrealized holding gain of $6 million, and $18 million, respectively.
- 14. Income Taxes:
The details of AEP's consolidated income taxes as reported are as follows:
Federal:
Current
$406 Deferred 60 Total 466 State:
current 61 Deferred 35 Total 96 International:
Current 1
Deferred 6
Total 7
Total Income Tax as Reported s5fia Year Ended December 31, 2001 2000 1999 (in millions)
$ 766 (237) 529 5o (9_)
41 6
21 27
$-59Z
$308 129 437 25 25 3
17 20
_482 The details of the registrant subsidiaries income taxes as reported are as follows:
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 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 Year Ended December 31, 2000 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
$ 9,126 (6,224) 2,1-902 (56)
(3.,414)
(3,470)
L*)
KPCo
$ 7,726 2,812 (1,180) 9,358 (2,725) 3,481 684 AEGCO
$ 8,746 (5,842) 2,904 (44)
(3.396)
(3,440)
L3__6)
APCO CPL (in thousands)
$ 71,623 27,198 (3,.237) 95,584 (19,165) 21,832 (1,528) 1,139
$96_
2
$190,671 (72,568)
(5,207) 112,896 (398) oPco PSO (in thousands)
$(62,298) 166,166 (2,495) 101,373 (21,600) 20,014 (794)
(2,380)
$ 53,030 (16,726)
(1.791) 34,51 352 352 APCO CPL (in thousands)
$129,165 3,838 (2,947) 130,056 327 4,764 (1,968) 3,123
$ 89,403 16,263 (5,207) 100,459 (5,073)
(5_07)
CSPCo
$ 88,013 14,923 (3,899) 99,037 (13,803) 17,885 (159) 3,923 I&M
$ 107,286 (45,785)
(7,377) 54,124 (10,590) 16,580 (947) 5,043 SWEPCo WTU
$ 77,965 (31,396)
(4,453) 42,116
$ 19,424 (11,891)
(1,271) 6,262 542 (691) 542
(
)
CSPCO I&M
$120,494 (7,746)
(3,379) 109,369 3,777 3,683
-(103) 7,357
$ 134,796 (126,748)
(7,524) 524 2,950 1,569 (330) 4,189 L-53
KPCo Year Ended December 31, 2000 OPCo PSO (in thousands)
SWEPCo WTU 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, 1999 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 Taxes as Reported Year Ended December 31, 1999 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 Taxes as Reported
$17,878 2,521 (1,187) 19,212 (50) 1,244 (65) 1,129
$259,608 (70,263)
(1,824) 187,521 15,426 4,307 (1,575) 18,158
$11,597 25,453 R35_,427259' (1,306)
(1.36
$16,073 14,653
-(4.482) 26,244 (1,476)
(1.476)
$ 6,774 9,401 (1,271) 14,904 (222)
(1,237)
(1,459)
$13.44 5 AEGCo APCo
$ 7,713 (5,282) 2l431
$69,522 8,981 (2.659) 75,844 CPL (in thousands)
$ 89,112 19,620 01207)
CSPco
$79,410 9,737 (3,432)
I&M
$(67,368) 85,345 (7,547) 10,430 (146)
(1,548)
(5,604)
(3,122) 1,529 4,052 318 744 382 (3,448)
(2.313)
(562)
(605)
(3))
19 (2940) 1,3 6 KPCo
$14,897 2,239 (1.193) 15,943 OPCo
$135,540 4,205 (1,825) 137,920 PSO (in thousands)
$20,777 14,521 SWEPCo WTU
$ 60,169 (17,347)
(4,565) 38,257
$ 3,328 12,026 (1275) 14,079 (424)
(3,256)
(2,215)
(4,826) 858 357 (539)
(99)
(1,633)
(166)
(5,428) 428215) 858 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.
Net Income Extraordinary Items (net of income tax $20 million in 2001,
$44 million in 2000 and $8 million in 1999) cumulative Effect of Accounting change (net of income tax $2 million in 2001)
Preferred stock Dividends Income Before Preferred Stock Dividends of Subsidiaries 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:
Depreci ati on Corporate Owned Life Insurance Investment Tax Credits (net)
Tax Effects of Foreign Operations Merger Transaction Costs State Income Taxes Other Total Income Taxes as Reported Effective Income Tax Rate Year Ended Decgmber 31, 2001 2000 1999 (in millions) 971
$267 972 50 (18) 10 1,013 569
$554 48 4
(37)
(27) 62 (35)
L-o L-54 35 11 313 597 M9G0
$319 77 247 (36)
(29) 49 26 (56) 14 19 1,005 482
$520 71 2
(38)
(54) 16 (35)
S2AU
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, 2001 Net Income (Loss)
Extraordinary (Gains) Loss Income Tax Benefit 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 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, 2001 Net Income Extraordinary Loss Income Tax Benefit 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 Year Ended December 31, 2000 Net Income (Loss)
Extraordinary (Gains) Loss Income Tax Benefit 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 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 AEGCO
$7,875 APCo CPL CSPCo (in thousands)
$161,818
$182,278
$161,876 I&M
$ 75,788 (6) 96,723 112,498 102,960 59,167
$258.541 2
$294.60
$ 2,557
$ 90,490
$104,050
$103,201 230 (1,078) 374 (3,414) 1,050 KPCo
$21,565 10,042 2,977 8,477 450 (4,765) 9,613 (2,042)
OPCo (i
$147,445 18,348 98,993 (5,207) 9,652 (4,474) 3*-.9%
PSO n thousand
$ 57,759 34,865 2,757 544 (4,058) 5,727 (5,211) 3_4_1.%1 SWEPCo ds)
$ 89,367 42,658
$11,062
$ 92,675
$32,418
$ 46,209 1,581 7,972 334 1,852 (420)
(1,252) 318 (1,581) 31.8%
AEGCo
$7,984 (536)
(3,289) 9,752 (9,969) 3$ 8A9 APCo (in
$ 73,844 (1,066)
(7,872) 133 179
$ 2,607
$ 69,330 452 (1,070) 374 (3,396) 784 3687) 7,606 54,824 (1,197)
(4,915) 9,950 (2,419)
$133,179 Lz-2%
(1,791)
(4,453) 5,137 5,451 (899)
(4,549)
S$
42_658 31--%
32_3%
CPL CSPCo thousands)
$189,567
$ 94,966 39,384 (14,148) 95,386 116,726
$99,733
$ 82,925
$ 47,234 21,224 (148)
(3,292)
(1,606)
(8,324) 6,137 (2,058)
WTU
$12,310 5,*571
$ 6,259 1,463 (1,271) 1,283 (2,163) 31L2%
I&M
$(132,032) 4,713
$(44,561) 7,556 10,529 20,378 29,259 42,587 (3,957)
(2,211)
(5,207) 2,296 (8_992,)11-50A (3,482) 89 (2,594)
A9u-Yz6 (7,854) 6,004 (5,673)
N-4.
Year Ended December 31, 2000 Net Income Extraordinary Loss Income Tax Benefit 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 Year Ended December 31, 1999 Net Income Extraordinary Loss Income Tax Benefit 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 Year Ended December 31, 1999 Net Income Extraordinary Loss Income Tax Benefit 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 Removal costs Investment Tax Credits (net)
State Income Taxes other Total Income Taxes as Reported Effective Income Tax Rate KPCo
$20,763 20,342 OPCo PSO SWEPCo (in thousands)
$ 83,737
$ 66,663
$72,672 40,157 (21,281) 205,679 33 9S3 24,768 530702440
$14,387
$107,903
$35,216
$ 34,104 1,827 27,577 5,149 84,453 (42 (1,25 1,59 (94 49, AEC
$ 6,
$ 1,
- 20)
- 52)
(3,398) 97 (1,988)
)
(8,868)
GCo APCo (i
.195
$120,492
.163) 76,035 762
$ 68,785 446 12,593 (1,069) 374 (3,448) 467 305 N. M.
KPCo
$25,430 (3,220)
(4,972) 3,305 (456) 3*Z oPco (in
$212,157 (1,791)
(
3,037 CPL n thousands)
$182,201 8,488 (2,971) 98,239
$285=957z
$100,085 7,981 (5,207) 6,965 (11,585)
PSO thousands)
$61,508 15,777 132,492 31.292
$14 3
$1,62
$3924800
$14,423
$120,628
$ 32,480 1,843 (420)
(1,292) 1,809 (586_)
17,517 198 (3,458) 1,090 (3.483)
$132,492 3S_ýY (1,791) 3,054 (2,451) 33__%
r WTU
$27,450 13,445
$14,313 1,204 4,482) 1,650
[6,504) 25.476 CSPCO
$150,27C 82,775 S233,045
$ 81,5(
(1,271)
(801)
I&M S$32,776 11,736 i6
$15,580 8,846 19,966 594 (3,347)
(2,174)
(3,991 5ý (3,70.
35-f SWEPCo 83,194 4,632 (1,621) 33,431 41,873 (4,565) 2,924 (6.801) 33..43 t)
(8,152) 8 (4,635)
- 1)
(6,096) 3%
M6A%
WTU
$26,406 8,402 (2,941) 14,937
$16,382 1,120 (1,275)
(1_290) 32I0%
The following tables show the elements of the net deferred tax liability and the significant temporary differences for AEP Consolidated and each registrant subsidiary:
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 Al other (net)
Net Deferred Tax Liabilities AEGCo APCc December 31, 2001 Deferred Tax Assets Deferred Tax Liabilities Net Deferred Tax Liabilities December 31, 2001 2000 (in millions)
$ 1,248
$ 1,248 (6,071)
(6,123)
$(3,963)
(245)
(160)
(268)
(332) 145 CPL (in thousands)
$(3,935)
(252)
(251)
(163)
(332) 58
$(4.875)
CsPco
$ 75,856
$ 162,334 130,863
$ 74,767 (103,831)
(865,909)
(1,294,658)
(518,489)
I&M
$ 332,225 (732,756)
Property Related Temporary Differences
$ (70,581)
Amounts Due From Customers For Future Federal Income Taxes 9,292 Deferred State Income Taxes (3,822)
Translation Regulatory Assets Net Deferred Gain on sale and Leaseback-Rockport Plant Unit 2 40,816 Accrued Nuclear Decommissioning Expense Deferred Fuel and Purchased Power Deferred cook Plant Restart Costs Nuclear Fuel Regulatory Assets Designated for Securitization All Other (net)
(3.680)
Net Deferred Tax Liabilities 2Z7)
KPCo December 31, 2001 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 Translation Regulatory Assets Deferred Fuel and Purchased Power Provision for Mine shutdown Costs All Other (net)
Net Deferred Tax Liabilities
$(530,298) $
(808,922) $(323,139) $(306,151)
(55,206)
(56,747)
(34,783)
(70,174)
(9,839)
(8,968)
(78,298)
(46,756)
(38,015) 27,157 43,707 (26,270)
(28,000)
(16,062)
(332,198)
(26,541) 47,499 (23,478)
(10,141)
$(0,7)
ILI-Ik*3_Zu)$4372)$4051 OPCo PSO (in thousands)
SWEPCo WTU 30,927
$ 135,938 59,421 56,189 22,888 (199,231)
(933,827)
(356.298)
(425,970)
(167,937)
$(118,147) $(595,974)
$(320,900)
$(362,884)
$(149,309)
(20,215)
(61,130)
(25,267)
(18,440)
(154,947) 20,323 18,365 (4.675)
(6,086)
- 4)
$7789 10,199 (6,441) 4,757 13,824 (456)
(497)
December 31, 2000 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 Translation Regulatory Asset 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 Regulatory Assets Designated for Securitization All other (net)
Net Deferred Tax Liabilities AEGCo APCo CPL (in thousands) 81,480
$ 178,487 67,184 (114,408)
(860.961)
(1309,981)
CSPCo 88,198 (510.957)
I&M
$ 342,900 (830,845)
$(487=945)
$ (78,113)
$(510,950) $
(773,454) $(343,045) $(324,198)
(72,426)
(11,142)
(68,817) 10,317 (55,085)
(5,478)
(86,351)
(40,554) 42,766 (332,198)
(2,420) 10,466 (64,719)
L$3292)
$(682.474)
L)
L-57 (55,218)
(69,982) 28,454 34,702 (39,395)
(42,000)
(28,319) 245 8.011
- (2.5)
$(i48794)
KPCo OPCo PSO SWEPCo WTU December 31, 2000 (in thousands)
Deferred Tax Assets 32,807
$ 330,878 60,010 47,615 16,604 Deferred Tax Liabilities (198,742)
(952,819).372,070)
(446,819)
(173,642)
Net Deferred Tax Liabilities
) I2
- 4) 1_(LP)
_1_(3
)
9$Z l
- 0)
Property Related Temporary Differences
$(116,109) $(586,039) $(313,248)
$(375,427)
$(150,264)
Amounts Due From Customers For Future Federal Income Taxes (19,680)
(57,759) 11,082 (6,015) 4,723 Deferred state Income Taxes (29,695)
(14,282)
(36,487)
Translation Regulatory Asset (53,149)
Deferred Fuel and Purchased Power (116,224)
Provision for Mine Shutdown costs 63,995 Postretirement Benefits 93,306 All other (net)
(451) 48,211 26 593 (17,762)
(11,497)
Net Deferred Tax Liabilities
$(6(59)
(41)
)
)
We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent's Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments.
Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.
COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax returns related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 the Company paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending the resolution of this matter.
As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced by $319 million in 2000. The Company has filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6 th Circuit.
The earnings reductions for affected registrant subsidiaries are as follows:
(in millions)
APCo
$ 82 CSPCo 41 I&M 66 KPCO 8
oPco 118 The Company has not recognized a deferred tax liability for temporary differences related to investments in certain subsidiaries located outside of the United States because such differences are deemed to be essentially permanent in duration. If the investments were sold, the temporary differences may become taxable resulting in a tax liability of approximately $66 million.
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.
- 15. Basic and Diluted Earnings Per Share:
The calculation of basic and diluted earnings per share is based on the amounts of income and weighted average shares shown in the table below.
Income:
Income before Extraordinary Item and cumulative Effect Extraordinary Losses (net of tax) cumulative Effect of Accounting change (net of tax)
Net Income weighted Average shares:
Average common shares outstanding Assumed conversion of stock options (see Note 11)
Diluted average comon shares outstanding 2001 2000 1999 (in millions -
except per share amounts)
$1,003
$302 (50)
(35) 18 9Z1 SZ1Z 322 322
$986 (14)
$-97U 321 323 322 321 Basic and Diluted Earnings Per share:
Income before Extraordinary item and cumulative effect
$3.11 $ 0.94 Extraordinary losses (net of tax)
(0.16) (0.11) cumulative effect of accounting change (net of tax) 0.06
$ 3.07 (0.04)
The assumed conversion of stock options does not affect income for purposes of calculating diluted earnings per share. Basic and diluted EPS are the same in 2001, 2000 and 1999 since the effect on weighted average shares outstanding is little or nil.
- 16. Supplementary Information:
Year Ended December 31, 2001 2000 1999 (in millions)
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 Noncash Investing and Financing Activities:
Acquisitions under capital Leases Assumption of Liabilities Related to Acquisitions Exchange of communication Investment for Common stock
$127
$972
$569
$17
$171
$86
$842
$449
$118
$64
$979
$270
$80
$5 L-59
.
S-3-01, 5-0--U 5-A-U
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, 2001, 2000, and 1999 were:
Year Ended December 31, 2001 Year Ended December 31, 2000 Year Ended December 31, 1999
- 17. Power, Distribution and Communications Projects:
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 1,788 MW.
AEP has other projects in various stages of development.
Investments in power projects that are 50% or less owned are accounted for by the equity method and reported in investments in power, distribution and communications projects on the balance sheet. At December 31, 2001, six domestic and four international power projects are accounted for under the equity method.
The six domestic projects are combined cycle gas turbines that provide steam to a host commercial customer and are considered Qualifying Facilities (QF) under the Public Utilities Regulatory Policies Act of 1978. The four international power plants are classified as Foreign Utility Companies (FUCO) under the Energy Policies Act of 1992. All of the power projects accounted for under the equity method have unrelated third-party partners.
All of the above power projects have project level financing, which is non-recourse to AEP.
AEP or AEP subsidiaries have guaranteed
$30 million of domestic partnership obligations for performance under power purchase agreements and for debt service reserves in lieu of cash deposits. AEP has guaranteed $94 million of additional equity for two projects.
APCo CSPCo I&M (in thousands)
$45,542
$12,626
$20,723 30,998 8,706 15,204 21,774 6,006 10,227 OPCo
$47,757 31,134 25,623 Distribution Projects We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we 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 our investment has been affected by the devaluation of the Brazilian Real.
The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively, net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2000 is approximately $33 million and $49 million, respectively, net of tax. Both investments are covered byla put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price.
As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option.
Management has evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and has concluded that our partners should be able to fulfill their responsibilities.
Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investment} As a result we will not recognize L-60
any future earnings from Vale and Caiua until the operating losses are recovered. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations.
Management will continue to monitor both the status of the losses and of its partners ability to fulfill its obligations under the put.
Communication Projects AEP provides telecommunication services to businesses and telecommunication companies through a broadband fiber optic network. AEP's investment in the network include fiber optic cable, electronic equipment and colocation facilities that house the equipment. The investments are both owned and leased with a majority of the leased investments being indefeasible rights of use (IRUs) for fiber optic cable for periods ranging from 20 to 30 years.
Telecommunication revenue is accounted for using the accrual method of accounting as service is rendered over the contractual term. Lease obligations related to these investment are included in the lease payment amounts disclosed in the lease note.
AEP has a 46.25% ownership interest in a joint venture, AFN networks, LLC (AFN),
which is engaged in the operation and construction of a fiber optic network. AFN both owns and leases fiber optic cable and electronic equipment with the majority of leases being IRUs of fiber optic cable for periods ranging from 20 to 25 years. AEP accounts for AFN under the equity method of accounting and has recorded its pro rata share of the losses during the start up phase.
AEP has a credit agreement with AFN that enables AFN to borrow up to $91.5 million at market interest rates to finance their construction and operations.
The amount available to AFN at December 31, 2001 is $61 million.
AEP has a 50% ownership interest in a joint venture, American Fiber Touch, LLC (AFT),
that is constructing a fiber optic line from Missouri to Illinois. AEP accounts for AFT under the equity method of accounting and has recorded its pro rata share of the losses of AFT during the start up phase. AEP has recently decided to withdraw from this venture and fully provided for the expected loss in exiting the joint venture in December 2001.
- 18. Leases:
Leases of property, plant and equipment are for periods up to 35 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:
Year Ended December 31, 2001 Lease Payments on operating Leases Amortization of Capital Leases Interest on Capital Leases Total Lease Rental Costs Year Ended December 31, 2001 Lease Payments on operating Leases Amortization of Capital Leases Interest on Capital Leases Total Lease Rental Costs Year Ended December 31, 2000 Lease Payments on Operating Leases Amortization of Capital Leases Interest on Capital Leases Total Lease Rental costs Year Ended December 31, 2000 Lease Payments on operating Leases Amortization of Capital Leases Interest on Capital Leases Total Lease Rental Costs Year Ended December 31, 1999 Lease Payments on operating Leases Amortization of Capital Leases Interest on Capital Leases Total Lease Rental Costs Year Ended December 31, 1999 Lease Payments on operating Leases Amortization of Capital Leases Interest on Capital Leases Total Lease Rental Costs AEP AEGCo APCo CPL CSPCo (in thousands)
$296,000 85,000 22,000
$76,262 281 55
$ 6,142 12,099 3_,789
$5,948
$ 7,063 7,206 2,396 I&M KPCo
$104,574 17,933 4,424
$1,191 2,740 808 OPCo PSO SWEPCo WTU (in thousands)
$63,913 14,443 5,818
$4,010
$2,277
$1,534 AEP AEGCo APCo CPL CSPCo (in thousands)
$237,000 121,000 38,000
$396000Q OPCo
$51,981 37,280 9 584 AEP
$247,000 97,000 35.000
$379.000
$73,858 281 55
$ 7,128 13,900 3,930 PSO SWEPCo (in thousands)
AEGCo
$74,269 364 64 will
$ 7,683 7,776 2_,690 APCo CPL CSPCo (in thousands)
$ 5,647 13,749 4,2_*67
$ 5,687 7,427 2,720 I&M KPCo
$ 81,446 26,341 10,908
$1,978 3,931 1,054 I&M KPCo
$ 81,611 $
199 11,320 4,299 9,338 1,162
$102,269
$.6 OPCo PSO SWEPCo WTU (in thousands)
$ 60,026 35,622 9,552 Property, plant and equipment under capital leases and Consolidated Balance Sheets are as follows:
Year Ended December 31, 2001 Property, Plant and Equipment under capital Leases Production Distribution other:
Mining Assets and Other Total Property, Plant and Equipment Accumulated Amortization Net Property, Plant and Equipment under Capital Leases AEP AEGCo
$ 40,000
$1,983 177,000 722,000 129 939,000 2,112 256,000 1,801 8.00$ 311 related obligations recorded on the APCo CSPco (in thousands)
$ 2,712
$ 6,380 82,292
$54._999 85,004 61,379 38,745 26,044 U4=,
$3,3 5
I&M 4,826 14,593 KPCo OPCo
$ 1,138 $ 22,477 86,267 17,658 114,944 105,686 18,796 137,421 43,768 9,213 57,429 obligations under capital Leases:
Noncurrent Liability
$356,000 Liability Due within one Year 95,000 Total obligations under Capital Leases
$45 76 235
$33,928 12,357
$27,052 7,835
$ 51,093 10,840
$ 61.93 3
$ 6,742 2,841
$ 64,261 16,405
$ 80 666 L-62
Year Ended December 31, 2000 Property, Plant and Equipment under capital Leases Production Distribution other:
Nuclear Fuel (net of amortization)
Mining Assets and Other Total Property, Plant and Equipment Accumulated Amortization Net Property, Plant and Equipment under capital Leases AEP AEGCo
$ 42,000 151,000 90,000 619,000 902,000 288,000
$2,017 177 2,194 1,603 APCo CSPCo (in thousands)
$ 6,276 93 437 99,713 36,553 I&M KPCo OPCo 2
7,023 14,595
$68 352 68,354 25,422 89,872 97,383 208,873 45,700
$ 1,730 $ 24,709 22,072 200,308 23,802 225,017 9,618 108,436 obligations under capital Leases:
Noncurrent Liability
$419,000 Liability Due within one Year 195,000 Total obligations under capital Leases
$614,000 358 233 59Z
$50,350 12,810
$35,199 7,733
$ 62,325 100,848
$11,091 $ 83,866 3,093 32,715 ILU-I Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.
CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under capital leases.
Future minimum lease payments consisted of the following at December 31, 2001:
Capital 2002 2003 2004 2005 2006 Later Years Total Future Minimum Lease Payments Less Estimated Interest Element Estimated Present value of Future Minimum Lease Payments AEP
$ 96,000 81,000 63,000 49,000 42,000 397,000 728,000 277,000 AEGCO
$217 132 20 6
1 376 65 53-U APCo (in
$13,718 11,625 9,371 6,440 4,690 53,457 CSPCo I&M thousands)
$ 8,932
$11,759 7,284 10,028 6,111 7,947 5,248 6,282 3,903 5,335 11,400 17,882 42,878 59,233 7,991 (2,700)
AEP Noncancellable Operal 2002 2003 2004 2005 2006 Later Years Total Future Minimum Lease Payments tina Leases
$ 286,000 271,000 255,000 245,000 243,000 2,671,000 oPCo Noncancellable operating Leases 2002
$ 62,945 2003 62,914 2004 63,323 2005 62,836 2006 63,242 Later Years 244,069 Total Future Minimum Lease Payments AEGCo APCO CPL (in thousands) 73,854
$ 3,193 73,854 3,108 73,854 2,402 73,854 2,155 73,854 1,887 1,181,664 4,563 PSO SWEPCo (in thousands)
$4,010
$ 2,277 4,010 2,277 4,010 2,277 4,010 2,277 4,010 2,277
$ 5,948 5,948 5,948 5,948 5,948 WTU
$1,534 1,534 1,534 1,534 1,534 CSPCo I&M
$ 2,104 1,991 1,623 1,308 1,279 82,627 79,923 77,104 75,736 75,595 1,186,678 L-63 KPCo
$ 3,093 2,441 1,824 1,449 891 1,548 11,246 1,663 OPCO
$ 18,516 17,521 14,701 11,520 10,305 28,948 101,511 20,845 KPCo 717 691 571 544 398 1,842
$614,000 $ 591 IEI-ILQ 142-9-U
Operating leases include lease agreements with special purpose entities related to Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers). The Rockport Plant lease resulted from a sale and leaseback transaction in 1989. The gain from the sale was deferred and is being amortized over the term of the lease which expires in 2022. The Gavin Scrubber lease expires in 2009. AEP has no ownership interest in the special purpose entities and does not guarantee their debt. The special purpose entities are not consolidated in AEP's financial statements in accordance with applicable accounting standards.
As a result, neither the leased plant and equipment nor the debt of the special purpose entities is included on AEP's balance sheet. The future lease payment obligations to the special purpose entities are included in the above table of future minimum lease payments under noncancellable operating leases.
- 19. Lines of Credit and Sale of Receivables:
The AEP System uses short-term debt, primarily commercial paper, to meet fluctuations in working capital requirements and other interim capital needs. AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries, including AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU and also incurs borrowings outside the money pool for other subsidiaries.
As of December 31, 2001, AEP had revolving credit facilities totaling $3.5 billion to support its commercial paper program.
At December 31, 2001, AEP had $3.2 billion outstanding in short term borrowings of which $2.9 billion was under these credit facilities. The maximum amount of such short-term borrowings outstanding during the year, which had a weighted average interest rate for the year of 4.95%, was $3.3 billion during March 2001.
The registrant subsidiaries incurred interest expense for amounts borrowed from the AEP money pool as follows:
AEGCo APCo CPL CSPCo I&M K PCo OPCo PSO SWEPCo WTU Year Ended December 31, 2001 2000 1999 (in millions) 0.8 9.8 11.4 16.9 14.1 5.0 1.4 13.1 0.8 2.3 14.6 9.2 6.3 7.5 2.0 3.4 4.2 4.7 3.1 2.7 0.6 Interest income earned from amounts advanced to the AEP money pool by the registrant subsidiaries were:
APCo CPL CSPCo T&M KPCo OPCo SWEPCo WTU Year Ended December 31.
2001 2000 1999 (in milTions) 1.7 0.1 0.8 1.1 1.6 9.0 0.1 1.8 8.6 3.4 0.1 0.1 0.2 Outstanding short-term Consolidated consisted of:
Balance Outstanding:
Notes Payable commercial paper Total debt for AEP December 31, 2001 2000 (in millions) 207 193 4,140 AEP Credit, which does not participate in the money pool, issued commercial paper on a stand alone basis up to May 30, 2001.
AEP Credit provides low-cost financing for utilities, including both AEP's electric utility operating companies and non-affiliates, through factoring receivables which arise primarily from the sale and delivery of electricity in the ordinary course of business. In January 2002 AEP Credit stopped purchasing accounts receivable from non-affiliated electric utility companies.
On May 30, 2001, AEP Credit stopped issuing commercial paper and allowed its $2 billion unsecured revolving credit facility to mature.
Funding needs were replaced on May 30, 2001 by a $1.5 billion variable funding note. The variable funding note was, in turn, replaced on December 31, 2001 when AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits.
Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquired from its clients to the commercial paper conduits and banks and receives cash.
This transaction constitutes a sale of receivables in accordance with SFAS 140 allowing the receivables to be taken off of AEP Credit's balance sheet. 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.
At December 31, 2001, the banks had a $1.2 billion commitment under the sale of receivables agreement to purchase receivables from AEP Credit of which $1 billion was outstanding. Of the
$1 billion of receivables sold, $485 million respresented non-affiliate receivables.
The commitment available under the sale of At year ended December 31, 2001, AEP Credit had:
Accounts Receivable sold Accounts Receivable Retained Interest Less uncol Iecti bl e Accounts and Pledged as collateral Deferred Revenue from Servicing Accounts Receivab1e Loss on sale of Accounts Receivable Initial variable Discount Rate Retained Interest if 10%
Adverse change in Uncollectible Accounts Retained Interest if 20%
Adverse change in Uncoll ecti bl e Accounts receivables agreement declines to $1.1 billion on January 31, 2002 and to $900 million on February 28, 2002, where it remains until the expiration of the commitment on May 30, 2002. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.
$ Millions 1,045 143 5
8 2.28%
142 140 Historical loss and delinquency amount for the Customer Accounts year ended December 31, 2001.
Receivable managed portfolio for the Customer Accounts Receivable Retained Miscellaneous Accounts Receivable Retained Allowance for uncollectible Accounts Retained Total Net Balance sheet Accounts Receivable Customer Accounts Receivable Securitized (Affiliate)
Customer Accounts Receivable securitized (Non-Affiliate)
Total Accounts Receivable managed Net uncollectible Accounts written off for the Year Ended December 31, 2001 Face value December 31. 2001
$ Millions 626 1,365 (109) 1,882 560 485 87 L-65
Customer Accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit as a pool between affiliate and non-affiliate accounts receivable. Miscellaneous Account Receivable have been fully retained and not securitized.
Delinquent Customer Accounts Receivable over 60 days old at December 31, 2001:
Affiliated Non-Affiliated Total (in millions)
$ 92 17 Sio~
The fees paid by the registrant subsidiaries to AEP Credit for factoring customer accounts receivable were:
Year Ended December 31, 2001 2000 1999 (in millions)
APCO CPL CSPCo I&M KPCO OPCo PSO SWEPCO WTU
$ 5.2 14.7 15.2 8.5 2.7 12.8 9.6 7.4 3.8 15.7 10.8 6.8 1.9 8.4 8.3 9.2 4.0 14.7 6.5 9.3 3.5 Under the factoring arrangement 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. At December 31, 2001 the amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows:
Company (in millions)
APCO
$ 61 CPL 89 CSPCo 106 I&M 95 KPCo 26 OPCO 100 Pso 43 SWEPCo 47 WTU 23
AG, L-66
- 20. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows:
M.
(In Millions -
Except Per share Amounts) operating Revenues operating Income Income Before Extraordi nary Items and cumulative Effect Net Income Earnings per share Before Extraordinary Items And cumulative Effect*
Earnings per Share**
(In Millions -
Except Per Share Amounts) arch 31 14,165 601 266 266 0.83 0.83 March 31 2001 Quarterly Periods Ended June 30 Sept. 30
$14,528 672 280 232 0.87 0.72
$18,385 862 403 421 1.25 1.31 2000 Quarterly Periods Ended June 30 Sept. 30 Operating Revenues
$6,117 operating Income 428 Income (Loss) Before Extraordinary Items and Cumulative Effect 140 Net Income (Loss) 140 Earnings (LOSS) per share Before Extraordinary Items and Cumulative Effect 0.43 Earnings (LOSS) per share 0.43 Amounts for 2001 do not extraordinary items and
- Amounts for 2001 do not add to $3.11 earnings per share before cumulative effect due to rounding.
add to $3.01 earnings per share due to The unaudited quarterly financial information for each AEP registrant subsidiary follows:
Quarterly Periods Ended 2001 March 31 Operating Revenues Operating Income Income (Loss) Before Extraordinary Items Net Income (Loss)
June 30 Operating Revenues Operating Income Income (LOSS)
Before Extraordinary Items Net Income (LOSS) seotember 30 Operating Revenues Operating Income Income Before Extraordinary Items Net Income December 31 Operating Revenues Operating Income Income (LOSS)
Before Extraordinary Items Net Income (Loss)
AEGCo APCo CPL (in thousands)
$60,507
$1,974,127 1,807 88,152 1,980 1,980 61,787 61,787
$52,217
$1,849,304 1,882 59,362 2,063 2,063
$57,417 1,615 2,051 2,051 36,419 36,419
$2,017,159 60,381 30,317 30,317
$57,407
$1,158,840 1,673 67,091 1,781 1,781 33,295 33,295 CsPco
$603,412
$1,125,573 64,152 51,932 35,031 35,031 37,671 37,671
$648,499
$1,109,095 82,351 62,894 52,518 52,518
$1,235,941 112,598 83,702 83,702 47,418 21,011
$1,297,704 76,920 65,318 65,318 I&M
$1,291,538 52,698 32,363 32,363
$1,259,874 47,340 27,374 27,374
$1,402,178 44,509 25,064 25,064
$833,875
$767,491
$850,035 36,630 60,431 15,158 13,536 11,027 41,493 37,876 (9,013)
(9,013)
L-67 Dec.
31
$14,179 260 54 52 0.17 0.16 Dec. 31
$8,137 308 (18)
(9)
(0.06)
(0.03)
$11,608 873 403 359 1.25 1.11
$10,844 395 (223)
(223)
(0.68)
(0.68) rounding.
Quarterly Periods Ended 2001 March 31 Operating Revenues Operating Income Income Before Extraordinary Items Net Income June 30 Operating Revenues Operating Income Income Before Extraordinary Items Net Income September 30 operating Revenues Operating Income Income Before Extraordinary Items Net Income December 31 Operating Revenues Operating Income Income (Loss)
Before Extraordinary Items Net Income (LOSS)
Quarterly Periods Ended 2000 March 31 operating Revenues Operating Income Income Before Extraordinary Items Net Income June 30 Operating Revenues operating Income Income Before Extraordinary Items Net Income september 30 operating Revenues Operating Income Income Before Extraordinary Items Net Income December 31 Operating Revenues Operating Income Income (Loss) Before Extraordinary Items Net Income (LOSS)
Quarterly Periods Ended 2000 March 31 Operating Revenues operating Income Income Before Extraordinary Items Net Income June 30 operating Revenues Operating Income Income Before Extraordinary Items Net Income September 30 Operating Revenues Operating Income Income Before Extraordinary Items Net Income December 31 Operating Revenues Operating Income Income (Loss) Before Extraordinary Items Net Income (LOSS)
KPCo
$459,157 12,604 7,075 7,075
$439,131 8,364 2,742 2,742
$485,820 12,587 5,312 5,312 OPCo PSO SWEPCo (in thousands)
$1,699,665 64,756 53,397 53,397
$1,627,177 47,067 32,094 10,579
$1,819,792 69,668 51,378 51,378
$275,287
$1,115,768 14,123 59,219 6,436 6,436 28,924 32,091
$356,139 8,340 (1,560)
(1,560)
$398,194 21,942 11,921 11,921
$910,428 59,914 51,069 51,069
$425,689 33,986 19,869 19,869
$434,795 32,649 17,784 17,784
$1,028,742 60,194 46,357 46,357 WTU
$195,006 5,392 891 891
$192,839 12,428 6,133 6,133
$429,623 17,745 14,067 14,067
$536,488
$685,222
$246,803 6,793 19,378 (2,175)
(3,670)
(3,670) 5,357 5,357 AEGCo APCo CPL CSPCo (in thousands)
$56,866 2,395 2,445 2,445
$56,928 1,746 1,653 1,653
$55,658 2,209 1,972 1,972
$59,064 2,074 1,914 1,914 KPCo
$231,454 15,557 8,052 8,052
$342,660 9,456 2,449 2,449
$359,296 13,790 6,761 6,761
$243,457 10,935 3,501 3,501 L-68
$1,021,678 78,246 47,664 47,664
$1,460,774 58,208 30,240 39,178
$1,538,340 65,750 36,112 36,112
$1,066,516 (1,050)
(49,110)
(49,110)
$316,328 38,650 8,139 8,139
$437,911 95,717 67,553 67,553
$795,794 120,653 89,974 89,974
$633,305 44,124 27,471 27,471
$928,332 50,798 35,335 35,335
$960,837 83,562 65,542 40,306 (8,781)
(8,781)
I&M
$708,150 (15,251)
(36,553)
(36,553)
$1,011,706 (18,599)
(39,181)
(39,181)
$1,060,654 36,056 15,190 15,190
$799,470
$643,141 761,574 52,078 17,393 (36,908) 23,901 (8,146)
(71,488) 23,901 (8,146)
(71,488)
OPCo PSO SWEPCo (in thousands)
$1,047,837 65,113 46,216 46,216
$1,436,330 79,968 58,233 58,233
$1,484,663 96,652 77,061 58,185
$161,329 10,860 1,165 1,165
$209,172 24,502 14,700 14,700
$555,236 56,437 54,329 54,329
$1,023,270
$504,282 (14,906) 4,870 (78,897)
(3,531)
(78,897)
(3,531)
$207,756 22,731 7,663 7,663
$272,409 33,296 18,786 18,786
$573,891 61,312 47,537 47,537
$628,670 10,939 (1,314)
(1,314)
WTU
$ 93,335 9,781 3,833 3,833
$130,742 16,938 8,070 8,070
$249,330 16,565 10,670 10,670
$286,155 9,057 4,877 4,877
Earnings for the fourth quarter 2001 increased $275 million from the prior year primarily due to the effect of charges recorded in 2000 from a ruling by the IRS disallowing interest deductions from AEP's COLI program and a write down for the proposed sale of Yorkshire. Fourth quarter 2001 earnings were also favorably impacted by the return to service in December 2000 of Unit 1 of the Cook Plant after an extended outage and the receipt of a contract cancellation fee from a non affiliated factoring client of AEP Credit.
- 21. Trust Preferred Securities:
The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2001 and December 31, 2000. They are classified on the balance sheets as Certain Subsidiaries Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. CPL reacquired 490,000 and 60,000 trust preferred units during 2001 and 2000, respectively.
units issued/
Description of outstanding underlying Business Trust Security At 12/31/01 Amount at December 31.
Debentures of Registrant 2001 2000 (in millions)
CPL capital 1 8.00%, series A 5,450,000
$136
$149
- CPL,
$141 million, a5 8.00%, Series A Pso Capital I 8.00%, series A 3,000,000 75 75 PSO, $77 million, 8.00%, series A SWEPCo capital I 7.875%, Series A 4,400,000 110 110
- SWEPCO,
$113 million,
$800 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 debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.
- 22. Minority Interest in Finance Subsidiary:
In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling preferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million.
Under the provisions of the Caddis formation agreements, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate (4.413% at December 31, 2001). The $750 million received replaces interim funding used to acquire Houston Pipe Line Company in June 2001.
The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such preferred stock is convertible into common stock of AEP upon the occurrence of certain events. AEP can elect not to have the transaction supported by such preferred stock if the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time.
The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements.
Steelhead has the right to terminate the transaction and liquidate 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
$321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest.
Liquidation of the preferred interest or of Caddis could impact AEP's liquidity.
Caddis and the AEP subsidiary which acts as its managing member 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 such managing member are consolidated with AqP for financial reporting purposes.
The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary.
- 23. Jointly Owned Electric Utility Plant:
CPL, CSPCo, PSO, SWEPCo and WTU have generating units that are jointly owned with unaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each AEP registrant subsidiary's proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments are reflected in its balance sheets under utility plant as follows:
Compn' Share Deoe'mbe 31.
2001 Percent Utility Construction of Plant work Ownership in service in Proqr ss CPL: Oklaunion Generating Station (Unit No.
- 1)
South Texas Project Generating Station (Units No.
1 and 2)
CSP:
W.C. Beckjord Generating Station (Unit No.
- 6)
Conesville Generating Station (Unit No. 4)
J.M. Stuart Generating Station Wm.
H. Zimmer Generating Station Transmission PSO:
oklaunion Generating Station (Unit No.
- 1)
SWEPCo:
Dolet Hills Generating Station (Unit No.
- 1)
Flint creek Generating Station (Unit No.
- 1)
Pirkey Generating Station (Unit No.
- 1)
WTU: Oklaunion Generating Station (Unit No.
- 1)
(a) varying percentages of ownership.
7.8 25.2 12.5 43.5 26.0 25.4 (a) 2000 Utility Construction Plant work in service in Progress (in thousands) 37,728 318 37,236 395 2.360.452
.1 373575 19,292
.M 14,292 81,697 193,760 704,951 61.476 884 494 27,758 2,634 91 14,108 80,103 191,875 706,549 61,820 178 261 10,086 5,265 451 15.6 82,646 S
$88,a8 R17 40.2 234,747 50.0 83,953 85.9 439,.430 675 213 231,442 82,899 437,069 51430
$ 1,984 852 435 54.7
$9 3,277.624
.295 L-70 (in thoulý
The accumulated depreciation with respect to each AEP registrant subsidiary's share of jointly owned facilities is shown below:
CPL CSPCO Pso SWEPCO WTU December 31, 2001 2000 (in thousands)
$863,130
$834,722 410,756 389,558 35,653 33,669 392,728 367,558 100,430 98,045
- 24. Related Party Transactions AEP System 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 preceding 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 transfer of S02 Allowances associated with transactions under the Interconnection Agreement. As part of AEP's restructuring settlement agreement filed with
- FERC, CSPCo and OPCo would no longer be parties to the Interconnection agreement and certain other modifications to its terms would also be made.
Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement.
Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps.
The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward contracts are recorded on a gross basis in the month when the contract settles.
In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area.
CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments.
The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. The CSW Operating Agreement has been accepted for filing and allowed to become effective by FERC.
AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone.
The following table shows the revenues derived from sales to the Pools and direct sales to affiliates for years ended December 31, 2001, 2000 and 1999:
APCo CSPCo I&M KPCo OPCo Related Party Revenues (in thousands)
AEGCo 2001 Sales to East System sales to west system Direct sales To East Direct Sales To west Other Total Revenues 2000 Sales to East System Sales to West System Direct Sales To East Direct Sales To West other Total Revenues 1999 Sales to East System Direct Sales To East other Total Revenues Related Party Revenues 2001 Sales to East System Sales to west system Direct Sales To East Direct Sales TO west other Total Revenues Pool Pool Affiliates Affiliates Pool Pool Affiliates Affiliates
$ 91,977 $44,185 $239,277 $34,735 $431,637 $
24,892 13,971 15,596 6,117 19,797 s
54,777 55,450 227,338 s
(3,133)
(1,705)
(1,905)
(744)
(2,590)
.772 11.060 2,0711 2.258 7,072 S$2ss~~~o '54,LV.3b6$27*
$ 81,013 7,697 s
59,106 s
4,092 2 770
$36,884 4,095 2,262 6,124 Pool
$ 41,869 $15,136 Affiliates 57,201 1 162 4.582 CPL Pool Pool Affiliates Affiliates 2000 Sales to East System Pool Sales to West System Pool Direct Sales To East Affiliates Direct Sales To West Affiliates Other Total Revenues 1999 Sales to West System Pool Direct Sales To west Affiliates other Total Revenues
$200,4741$36,554 4,614 1,829 2,510 972 2 710 2,466
$502,140 $
6,356 66,487 227,983 3,421 4,043
$50,624 $43,157 $337,699 $
50,968 152,559 345$
1 145 825 PSO SWEPCo WTU (in thousands) 4 19,865 3,317 3,697 2,833 12,617 30,668 5 583 (51) 23,421 7,323 (3,348) (1,990) 12,516 21,995 5 163 (12.680)
$ 6,124 7,470 14 177
$ 3,097 7,968 2 652 8,073 322 3,238 1,228 67,930 9,350 7 81 5,546 194 (3,008) (1,116) 62,178 7,645
$ 4,527 $
401 49,542 2,576 48 11 790 The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2001, 2000, and 1999:
Related Party Purchases 2001 Purchases from East System Purchases from west System Direct Purchases from East Direct Purchases from west 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)
Pool
$346,582 $292,034 Pool 296 165 Affiliates Affiliates Pool Pool Affiliates Affiliates 1999 Purchases from East System Pool Direct Purchases from East Affiliates Total Purchases
$355,305 $287,482 455 260 14 8
$130,991 $199,574 OPCo
$ 79,030 $ 61,816
$62,350 185 72 235 159,022 68,316
$106,644 $ 58,150 285 108 158,537 69,446 9
3
$112,350
$19,502 88.022 4 498
$200.372
$50,339 390 12
$ 20,864 L-72
Related Party Purchases 2001 Purchases from East System Purchases from West System Direct Purchases from East Direct Purchases from West Total Purchases CPL PSO SWEPCO (in thousands)
Pool Pool Affiliates Affiliates 415 12,657 45.569
$ 1,327 5,877 37,445 34,603 2000 Purchases from East System Pool
$20,100 Purchases from west System Pool 1,696 5,386 Direct Purchases from East Affiliates 251 2,117 Direct Purchases from west Affiliates 301644 Total Purchases HEM 1999 Purchases from west system Pool 895
$ 6,992 Direct Purchases from west Affiliates 15,778 27,627 Total Purchases L
6 WTU 4
3,810 11,689 27,744 4,614 9,696 40 349
$5 4,379 18,444 695 71 8 264 39,258
$1,295 $ 7,266 6,256 19.325
$2659 The above summarized related party revenues and expenses are reported in their entirely, without elimination, and are presented as operating revenues affiliated and purchased power affiliated on the income statement of each AEP Power Pool member. Since all of the above pool members are included in AEP's consolidated results, the above summarized related party transactions are eliminated in total in AEP's consolidated revenues and expenses.
AEP System Transmission Pool APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above).
Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio."
The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 1998, 1999 and 2000:
1999 APCo CSPCo I&M KPCo opco
$ (8,300) 39,000 (43,900)
(4,300) 17,500 2000 (in thousands)
$ (3,400) 38,300 (43,800)
(6,000) 14,900 2001
$ (3,100) 40,200 (41,300)
(4,600) 8,800 CPL, PSO, SWEPCo, WTU 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.
AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries.
Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern:
"* 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 Power Agreements and Other A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant.
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 I&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 I&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.
Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30%
of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for the right to receive sucl power the same amounts which L-74
I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement expires on December 31, 2004.
APCo and OPCo, jointly own two power plants. The costs of operating these facilities are apportioned between the owners based on ownership interests.
Each company's share of these costs is included in the appropriate expense accounts on each company's consolidated statements of income. Each company's investment in these plants is included in electric utility plant on its consolidated balance sheets.
I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from barging services as nonoperating income.
AEGCo, APCo and OPCo record costs paid to I&M for barging services as fuel expense.
The amount of affiliated revenues and affiliated expenses were:
Company I&M -
revenues AEGCo -
expense APCo
- expense OPCo - expense Year Ended December 31, 2001 2000 1999 (in millions)
$30.2 8.5 11.5 10.2
$23.5 8.8 7.8 6.9
$28.1 8.5 10.5 9.1 American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS The following is a
combined presentation of management's discussion and analysis of financial condition, contingencies and other matters for AEP and certain of 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, contingencies and other matters and the registrant to which they apply:
Financial condition Market Risks Industry Restructuring Litigation Environmental Concerns and Issues other Matters
- AEP, APCo,
- CPL, I&M,
- OPCo, SWEPCo
- AEP, AEGCo,
- APCo, CPL,
- CSPCo, I&M,
- KPCO, OPCO,
- PSO, SWEPCo, WTU
- AEP, APCo,
- CPL, CSPCo, I&M,
- OPCo, PSO,
- SWEPCo, WTU
- AEP, AEGCo,
- APCo, CPL,
- CSPCo, I&M,
- KPCo, OPCo,
- PSO, SWEPCo, WTU
- AEP, APCo,
- CPL, CSPCo, I&M,
- OPCo, SWEPCo
- AEP, AEGCo,
- APCo, CPL,
- CSPCo, I&M,
- KPCo, OPCo,
- PSO, SWEPCo, WTU Financial Condition -
Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo We measure our financial condition by the strength of the balance sheet and the liquidity provided by cash flows and earnings.
Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality.
Year-end ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table:
Company APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCO WTU The ratings senior unsecured following table:
Comran_
AEP AEP Resources*
APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCO Moody's S&P A3 A3 A3 Baal Baal A3 Al Al A2 A
A A
A A
A A
A A-Fitch A
A A
BBB+
BBB+
A A+
A+
A at the end of the year for debt are listed in the Moody's s&P Baal Baal Baal Baal A3 Baa2 Baa2 A3 A2 A2 BBB+
BBB+
BBB+
BBB+
BBB+
BBB+
BBB+
BBB+
BBB+
BBB+
Fitch BBB+
BBB+
BBB+
A A
BBB BBB BBB+
A A
- The rating is for a series of senior notes issued with a Support Agreement from AEP.
The ratings are presently stable.
AEP's commercial paper program has short term ratings of A2 and P2 by Moody's and Standard and Poor's, respectively.
AEP's common equity to total capitalization declined to 33% in 2001 from 34% in 2000. Total capitalization includes long-term debt due within one year, minority interests and short-term debt. Preferred stock at 1% remained unchanged. Long-term debt increased from 47% to 50% while short-term debt decreased from 18% to 13% and minority interest in finance subsidiary increased to 3%. In 2001 and 2000, AEP did not issue any shares of common stock to meet the requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan.
M-1
We plan to strengthen the balance sheet in 2002 by issuing AEP common stock and mandatory convertible preferred stock and using the proceeds from asset sales to reduce debt. The issuance of common stock has the potential to dilute future earnings per share but will enhance the equity to capitalization ratio.
Rating agencies have become more focused in their evaluation of credit quality as a result of the Enron bankruptcy. They are focusing especially on the composition of the balance sheet (off-balance sheet leases, debt and special purpose financing structures), the cash liquidity profile and the impact of credit quality downgrades on financing transactions.
We have worked closely with the agencies to provide them with all the information they need, but we are unable to predict what actions, if any, they may take regarding our current ratings.
During 2001 AEP's cash flow from operations was $2.9 billion, including $971 million from net income and $1.5 billion from depreciation, amortization and deferred taxes.
Capital expenditures including acquisitions were $4 billion and dividends on common stock were $773 million.
Cash from operations less dividends on common stock financed 52% of capital expenditures.
During 2001, the proceeds of AEP's
$1.25 billion global notes issuance and proceeds from the sale of a UK 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 units (see discussion in Note 8).
Asset purchases include HPL, coal mines, a barge line, a wind generating facility and two coal fired generating plants in the UK.
These acquisitions accounted for the increase in total debt in 2001. During the third quarter of 2001, permanent financing was completed for the acquisition of HPL by the issuance of a minority interest which provided $735 million net of expenses (See Note 22 for discussion of the terms). HPL's permanent financing increased funds available for other corporate purposes. Long-term financings for the other acquisitions will be announced as arranged.
Long-term funding arrangements for specific assets are often complex and typically not completed until after the acquisition.
Earnings for 2001 resulted in a
dividend payout ratio of 80%, a considerable improvement over the 289% payout ratio in 2000. The abnormally high ratio in 2000 was the result of the adverse impact on 2000 earnings from the Cook Plant extended outage and related restart expenditures, merger costs and the write-off related to COLI and non-regulated subsidiaries. We expect continued improvement of the payout ratio as a result of earnings growth in 2002.
Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged.
Some acquisitions of existing business entities include the assumption of their outstanding debt and certain liabilities. Sources of long term funding include issuance of AEP common stock, minority interest or long-term debt and sale-leaseback or leasing arrange ments. The domestic electric subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short term debt through issuances of long-term debt and additional capital contributions from their parent company. We operate a money pool and sell accounts receivables to provide liquidity for the domestic electric subsidiaries.
Short-term borrowings in the U.S.
are supported by two revolving credit agreements.
At December 31, 2001, approximately $554 million remained available for short-term borrowings in the US.
Subsidiaries that trade energy commodities in Europe have a separate multicurrency revolving loan and letters of credit agreement allowing them to borrow up to 150 million Euros of which 42 million Euros were available on December 31, 2001.
In February 2002 they also originated a
temporary second line of 50 million Euros for three months which is expected to be replaced with a 150 million Euro line, M-2
providing for a total of 300 million Euros.
SEEBOARD, Nanyang and Citipower which operate in the UK, China and Australia, respectively, each have independent financing arrangements which provide for borrowing in the local currency. SEEBOARD has a 320 million pound revolving credit agreement it uses for short-term funding purposes.
At December 31,
- 2001, SEEBOARD had 117 million pounds available.
Our revolving credit agreements include covenants that require us to maintain specified financial ratios and describe non performance of certain actions as events of default. At December 31, 2001 we complied with the covenants of these agreements. In general, a default in excess of $50 million under one agreement is considered a default under the other agreements. In the case of a default on payments under these agreements, all amounts outstanding would be immediately payable.
M-3
The contractual obligations of AEP include amounts reported on the balance sheet and other obligations disclosed in our footnotes. The following table summarizes AEP's contractual cash obligations at December 31, 2001:
Contractual Cash obligations Long-term Debt short-term Debt Trust Preferred Securities Minority Interest In Finance Subsidiary (a)
Preferred stock subject to Mandatory Redem tion capital Lease obligations ilncnnditinnal purrchase Less Than 1 year
$2,300 3,155 96 Payments Due by Period (in millions) 2-3 years 4-5 years A
$2,988
$2,559 750 24 144 4
91 fter 5 years Total
$ 4,246
$12,093 3,155 321 321 750 67 95 397 728 obligatio*os (b) 317 1,658 1,299 3,559 6,833 Noncancellable operating Leases 286 526 488 2,671 3,971 other Long-term obligations (c) 31 30 61 Total Contractual cash obligations (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.
(c) Represents contractual obligations to loan funds to a joint venture accounted for under the equity method.
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 J for the timing of debt payment obligations and the lease footnote (Note 18) in section L for the timing of rent payments.
Special purpose entities 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 Plant's flue gas desulfurization system (Gavin Scrubbers), the permanent financing of HPL and the sale of accounts receivable use special purpose entities. Neither AEP nor any AEP related parties has an ownership interest in the special purpose entities. AEP does not guarantee the debt of these entities. These special purpose entities are not consolidated in AEP's financial statements in accordance with generally accepted accounting principles. As a result, neither the assets nor the debt of the special purpose entities is included on AEP's balance sheet. The future cash obligations payable to the special purpose entities are included in the above table In addition to the amounts disclosed in the contractual cash obligations table above, AEP and certain subsidiaries make commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments.
AEP's commitments outstanding at December 31, 2001 under these agreements are summarized in the table below:
other commercial commitments standby Letters of Credit Guarantees Construction of Generating and Transmission Facilities for Third Parties (a) nthier cnmmrrcial Amount of Commitment Expiration Per Period (in millions)
Less Than 1 year 2-3 years 4-5 years After 5 years Total 101
$ 53
$36 190 815 161 15 991 168 540 708 commitments (b) 6 45 40 24 115 Total commercial Commitments i,
IM M
M (a) As construction agent for third party owners of power plants and transmission facilities, the company has committed by contract terms to complete construction by dates specified in the contracts. should the company default on these obligations, financial payments could be up to 100% of contract value (amount shown in table) or other remedies reguired by contract terms.
(b) Represents estimated future payments for power to be generated at facilities under construction.
M-4 IL4Z
With the exceptions of SWEPCo's guarantanee of an unaffiliated mine operator's obligations (payable upon their default) of
$111 million at December 31, 2001, and OPCo's obligations under a power purchase agreement of $6 million in 2002 and $16 million each year in 2003 through 2005, the obligations in the above table are commitments of AEP and its non-registrant subsidiaries.
AEP, through certain subsidiaries, has entered into agreements with an unrelated, unconsolidated special purpose entity (SPE) to develop, construct, finance and lease a power generation facility. The SPE will own the power generation facility and lease it to an AEP consolidated subsidiary after construction is completed. The lease will be accounted for as an operating lease with the payment obligations included in the lease footnote.
Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to an unrelated industrial company which will both use the energy produced by the facility and sell excess energy. Another affiliate of AEP has agreed to purchase the excess energy from the subleasee for resale.
The SPE has an aggregate financing commitment from equity and debt participants (Investors) of $427 million. AEP, in its role as construction agent for the SPE, is responsible for completing construction by December 31, 2003. In the event the project is terminated before completion of construction, AEP has the option to either purchase the project for 100% of project costs or terminate the project and make a payment to the Lessor for 89.9%
of project costs.
The term of the operating lease between the SPE and the AEP subsidiary is five years with multiple extension options. If all extension options are exercised the total term of the lease would be 30 years. AEP's lease payments to the SPE are sufficient to provide a return to the Investors. At the end of the first five-year lease term or any extension, AEP may renew the lease at fair market value subject to Investor approval; purchase the facility at its original construction cost; or sell the facility, on behalf of the SPE, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Investors, AEP may be required to make a payment to the Lessor of up to 85% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to the SPE during the construction and post-construction periods.
As of December 31, 2001, project costs subject to these agreements totaled
$168 million, and total costs for the completed facility are expected to be approximately $450 million. Since the lease is accounted for as an operating lease for financial accounting purposes, neither the facility nor the related obligations are reported on AEP's balance sheets. The lease is a variable rate obligation indexed to three-month LIBOR. Consequently as market i interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately
$12 million represent future minimum payments under the first five-year lease term calculated using the indexed LIBOR rate of 2.85% at December 31, 2001.
The lease payments and the guarantee of construction commitments are included in the Other Commercial Commitments table above.
OPCo has entered into a purchased power agreement to purchase electricity pro duced by an unaffiliated entity's three-unit natural gas fired plant that is under construction. The first unit is anticipated to be completed in October 2002 and the agree ment will terminate 30 years after the third unit begins operation. Under the terms of the agreement OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated. For the remainder of the 30 year contract term, OPCo will pay the variable costs to generate the electricity it pur chases which could be up to 20% of the plant's capacity. The estimated fixed pay ments through December 2005 are $55 million and are included in the Other Commercial Commitments table shown above.
M-5
Minority Interest in Finance Subsidiary In August 2001, AEP formed Caddis
- Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling pre ferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agree
- ments, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate (4.413% at December 31, 2001). The $750 million received replaced interim funding used to acquire Houston Pipe Line Company in June 2001.
The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such preferred stock is convertible into common stock of AEP upon the occurrence of certain events.
AEP can elect not to have the transaction supported by such preferred stock if the preferred interest were reduced by $225 million.
In addition, Caddis has the right to redeem the preferred member interest at any time.
The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred
- rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements.
The credit agreement between Caddis and the AEP subsidiary that acts as its managing member contains covenants that restrict incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions.
Financial covenants impose minimum financial ratios. At December 31, 2001, we satisfied all of the financial ratio requirements. In general, a default in excess of $50 million under another agreement is considered a default under this agreement.
Steelhead has the right to terminate the transaction and liquidate 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
$321.4 million of AEP subsidiary preferred stock into AEP common stock.
If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could impact AEP's liquidity.
Caddis and the AEP subsidiary which acts as its managing member 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 such managing member are consolidated with AEP for financial reporting purposes.
The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary.
Expenditures for domestic electric utility construction are estimated to be $4.6 billion for the next three years. Approximately 100% of those construction expenditures are expected to be financed by internally generated funds.
Construction expenditures for the registrant subsidiaries for the next three years excluding AFUDC are:
APCo CPL I&M OPCo SWEPCo Projected construction Expenditures (in millions) 815.5 573.1 556.9 1,008.0 321.4 Construction Expenditures Financed with Internal Funds 92%
80%
ALL 68%
92%
In 1998 SEEBOARD's 80% owned subsidiary, SEEBOARD Powerlink, signed a 30-year contract for $1.6 billion to operate, maintain, finance and renew the high-voltage power distribution network of the London M-6
Underground transportation system.
SEEBOARD Powerlink will be responsible for distributing high voltage electricity to supply 270 London Underground stations and 250 miles of the rail system's track. SEEBOARD's partners in Powerlink are an international electrical engineering group and an international cable and construction group.
Financing Activity AEP issued $1.25 billion of global notes in May 2001 (with intermediate maturities).
The proceeds were loaned to regulated and non-regulated subsidiaries.
In 2001 CSPCo and OPCo, AEP's Ohio subsidiaries, reacquired $295.5 million and
$175.6 million, respectively, of first mortgage bonds in preparation for corporate separation.
AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies and certain non-affiliated electric utility companies.
AEP Credit's financing for the purchase of receivables changed during 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 the balance sheet. The agreement expires in May 2002 and is expected to be renewed. At December 31, 2001, AEP Credit had $1.0 billion sold under this agreement of which $485 million are non affiliated receivables. In January 2002, AEP Credit stopped purchasing accounts receivables from non-affiliated electric utility companies.
In February 2002 CPL issued $797 million of securitization notes that were approved by the PUCT as part of Texas restructuring to help decrease rates and recover regulatory assets. The proceeds were used to reduce CPL's debt and equity.
In 2002 AEP plans to continue restructuring its debt for corporate separation assuming receipt of all necessary regulatory approvals. Corporate separation will require the transfer of assets between legal entities.
With corporate separation, a newly created holding company for the unregulated business is expected to issue all debt needed to fund the wholesale business and unregulated generating companies. The size and maturity lengths of the original offering is presently being determined.
The regulated holding company is expected to issue the debt needed by the wires companies in Ohio and Texas.
The regulated integrated utility companies will continue their current debt structure until the regulatory commissions approve changes. At that time, the regulated holding company may also issue the debt for the regulated companies' funding needs.
We have requested credit ratings for the holding companies consistent with our existing credit quality, but we cannot predict what the outcome will be.
AEP Uses a money pool to meet the short-term borrowings for certain of its subsidiaries, primarily the domestic electric utility operations.
Following corporate separation, management will evaluate the advantages of establishing a money pool for the unregulated business subsidiaries. The current money pool which was approved by the appropriate regulatory authorities will continue to service the regulated business subsidiaries, Presently, AEP also funds the short-term debt requirements of other subsidiaries that are not included in the money pool. As of December 31, 2001, AEP had credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2001, AEP had $2.9 billion outstanding in short-term borrowing subject to these credit facilities.
Market Risks -
Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU As a major power producer and trader of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include com modity prico risk, interest rate risk, foreign exchange riik and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or M-7
rates.
Policies and procedures are established to identify, assess, and manage market risk exposures in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by a Chief Risk Officer. The Risk Management Committee establishes risk
- limits, approves risk
- policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels.
This committee receives daily, weekly, and monthly reports regarding compliance with
- policies, limits and procedures.
The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P.
Market Risk Oversight, and senior financial and operating managers.
We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95%
confidence level and a one-day holding period.
Based on this VaR analysis, at December 31, 2001 a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.
The following table shows the high, average, and low market risk as measured by VaR at:
December 31.
2001 2000 High Average Low High Average LOW (in millions)
AEP
$28
$14
$5
$32
$10
$1 APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU 4
3 2
3 1
3 2
3 1
1 1 1
1 1
1 1
1 6
4 3
4 1 5
3 4
1 2
1 1 1
2 1
1 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 $673 million at December 31, 2001 and $998 million at December 31, 2000.
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:
December 31, 2001 2000 (in millions)
Coman AEGCo APCo CPL CSPCo I&M KPCo OPCo PSO SWEPCo WTU 5
100 80 60 86 16 59 17 36 20 4
149 135 84 129 31 112 44 60 24 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 CPL and WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia. 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.
M-8
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 coal, oil, natural gas liquids, and emission allowances and as a result the Company is 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 the limits unless specifically approved by the Risk Management 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 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.
AEP limits credit risk by extending unsecured credit to entities based on internal ratings.
In addition, AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis.
This
- data, in conjunction with the ratings information, is used to determine appropriate risk parameters.
AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business.
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 is not material to financial condition at December 31, 2001. At December 31, 2001 less than 5%
of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price.
The following table approximates counterparty credit quality and exposure for AEP.
Counterparty Credit Quality:
December 31, 2001 AAA/Exchanges AA A
BBB Below Investment Grade Total
- Futures, Forward ar Swap Contracts
$ 147 140 304 932 56 Options Total (in millions) 4 7
34 23
$ 147 144 311 966 79 ssaM
=
14 The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP.
We enter into transactions for electricity anid natural gas as part of wholesale trading operations.
Electric and gas transactions are executed over the counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission.
Brokers and counterpartles require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at December 31, 2001 and 2000 was $55 million and $95 million. These margin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet. We can be subject to further margin requirements should related commodity prices change.
We recognize the net change in the fair value Of all open trading contracts, a practice ccimmonly called mark-to-market accountingj in accordance with generally M-9
accepted accounting principles and include the net change in mark-to-market amounts on a
net discounted basis in revenues.
Unrealized mark-to-market revenues totaled
$257 million in 2001. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts are based mainly on Company developed valuation models.
The valuation models produce an estimated fair value for open long term trading contracts.
This fair value is present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Forward price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask prices. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price of the bid ask prices if we have a long position and the ask side if we have a short position.
This provides for a conservative valuation net of the reserves.
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 risks, at the time of settlement, do not correlate with the Company developed price models.
The effect on the Consolidated Statements of Income of marking to market open electricity trading contracts in the Company's regulated jurisdictions is deferred as regulatory assets or liabilities 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 mark-to-market revenues (the change in fair value of open trading contracts).
Revenues (including mark-to market adjustment)
Fuel and Purchased Energy Expense Net Revenues Mark-to-Market Revenues Percentage of Net Revenues Represented by Mark-to-Market December 31, 2001 2000 1999 (in millions)
$61,257
$36,706
$24,745 52,753 28,718 Sim0 17.244 I23.5p M2 2%
2%
M-10 z.
'
The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Energy Trading Contracts" shows how the net fair value of energy trading contracts was derived from the amounts included in the balance sheet line item "energy trading and derivative contracts." The next table "Energy Trading Contracts" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts at the beginning of the year of $63 million to the end of the year of $448 rillion. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Energy Trading 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 Energy Trading Contracts December 31, 2001 2000 (in millions)
Energy Trading Contracts:
Current Asset
$ 8,536
$ 15,495 Long-term Asset 2,367 1,552 Current Liability (8,279)
(15,671)
Long-term Liability (2.176)
(1,313)
Net Fair value of Energy Trading contracts 44 i$
63 The net fair value of energy trading contracts includes $257 million at December 31, 2001 and
$170 million at December 31, 2000 of unrealized mark-to-market gains that are recognized in the income statement. Also included in the above net fair value of energy trading contracts are option premiums that are deferred until the related contracts settle and the portion of changes in fair values of electricity trading contracts that are deferred for ratemaking purposes.
Energy Trading Contracts AEP consolidated (in millions)
Total Net Fair value of Energy Trading contracts at December 31, 2000 63 Gain from Contracts realized/settled during period (352)
(a)
Fair value of new open contracts when entered into during period 73 (b)
Adjustments for Contracts entered into and settled during period 310 (a)
Net option premium payments 24 change in fair value due to valuation Methodology changes (1)
(c) changes in market value of contracts 331 (d)
Net Fair value of Energy Trading contracts at December 31, 2001
$A48 (e)
(a) Gains from Contracts Realized or Otherwise Settled During the Period" include realized gains from energy trading contracts that settled during 2001 that were entered into prior to 2001, as well as during 2001.
"Adjustment for Contracts Entered into and settled During the Period" discloses the realized gains from settled energy trading contracts that were both entered into and closed within 2001 that are included in the total gains of $352 million, but not included in the ending balance of open contracts.
(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 2001.
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) The Company changed its methodology for calculating and reporting load based transactions.
The previous methodology estimated a baseload volume based on historical takes and sold a call option for potential load increases from the baseloaq.
The current methodology uses a modified version of a straddle load follow model to estimate the baseload volume and call option volume.
This methodogy change more accurately estimates the load volume forecast.
The dollar impact on existing deals was a decrease of injfair value of $1.2 million.
(d)
"Change 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.
(e)
The net change in the fair value of energy trading contracts for 2001 that resulted in an increase of $385 million ($448 million less $63 million) represents the balance sheet change.
The net mark-to-market gain on energy trading contracts of $257 million represents the impact on earnings.
The difference is related primarily to regulatory deferrals of certain mark-to-market gains that were recorded as regulatcry liabilities and not reflected in the income statement for those companies that operate in regulated jurisdictions, and deferrals of option premiums included in the above analysis, which do not have a mark-to market income statement impact.
M-11
Energy Trading Contracts (in thousand)
Net Fair Value of Energy Trading Contracts at December 31, 2000 Loss/(Gain) from Contracts Realized/settled during period Fair value of new open Contracts when entered into during period Adjustments for Contracts Entered into and settled during period Net option premium payments change in fair value due to valuation Methodology changes changes in market value of Contracts Net Fair Value of Energy Trading Contracts at December 31, 2001 Energy Trading Contracts (in thousands)
Net Fair Value of Energy Trading Contracts at December 31, 2000 Loss/(Gain) from contracts Realized/settled during period Fair Value of new open contracts when entered into During period Adjustments for Contracts Entered into and settled During period Net option premium payments change in fair value due to valuation Methodology changes changes in market value of Contracts Net Fair Value of Energy Trading Contracts at December 31, 2001 Energy Trading Contracts (in thousands)
Net Fair Value of Energy Trading Contracts at December 31, 2000 LosS/(Gain) from contracts Realized/settled during period Fair value of new open Contracts when entered into During period Adjustments for Contracts Entered into and settled during period Net option premium payments Change in fair value due to valuation Methodology changes changes in market value of contracts Net Fair Value of Energy Trading Contracts at December 31, 2001 APCo 7,447 CPL CSPCo
$(8,191)
$ 3,769 (12,478) 4,221 (11,522) 13,441 9,635 40,755 1,072 (220) 25,684 I&M
$ (6,845) 2,602 (158)
(425)
KPCo
$ 1,678 8,245 24,998 658 (135) 22,436 OPCO
$ 5,613 (10,982)
(3,298)
(10,861) 8,921 3,315 27,049 712 (146) 42.636 10,051 264 (54) 773 PSO SWEPCo
$(6,508)
$(7,795) 2,483 7,338 1,981 (120)
(2,740) 2,938 8,422 2,274 (138)
(2,801) 11,213 34,001 894 (183) 24,769 WTU
$(2,590) 5,881 2,861 773 (46)
(5_96)
M-12
Energy Trading Contract Maturities AEP consolidated source of Fair value Prices actively quoted (a)
Prices provided by other external sources (b)
Prices based on models and other valuation methods (c)
Total Energy Trading Contract Maturities source of Fair value APCO Other External Sources Model s/other valuation Total CPL other External sources Models/other valuation Total CSP other External sources Model s/other valuation Total KEPCo other External sources Models/Other valuation Total I&M Other External sources Models/other valuation Total OPCo other External sources Models/other valuation Total PSO other External sources Model s/Other valuation Total SWEPCo other External Sources Models/other valuation Total WTU other External Sources Models/other valuation Total Fair Value of Contracts at December 31,2001 Maturities (in millions)
Less than In Excess Tot 1 Year 1-3 years 4-5 years of 5 years val
$ 46 152 13 8
33 133 117A al Fair ue
$ 54 185 35 M35 28 209 S448 Fair value of Contracts at December 31,2001 Maturities (in thousands)
Less than In Excess Total Fair 1 year 1-3 years 4-5 years of 5 years value 13,366 3,215 9,588 34,318 (5,245) 1,681
(
6016 9,867 2,373 5,872 21,018 6,801 1
1,192
!_M5 119 5,153 5,153 (1,475) 2,361 (355) 8451 17,237 4,146 13,058 3,141 6,481 23,197 7,987 28 587 (4,400) 1,280 (1058) 48 SS2
.861 (4,965) 1,469 (1,194) 5259 (1,743) 499 (419)
.786 1,675 5,665 1.123 908 1042 354 3_5 22,954 52,747 (3,564) 7421 15,739 32,710 886 112843 23,718 37,627 21,045 44,40 (3,120) 5,554 (3,496) 6,396 (1,244) 2,159 (a) "Prices Actively Quoted" represents the company's exchange traded futures positions in natural gas.
(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.
Prices for these various commodities can generally be obtained on the over the-counter market through 2003.
some prices from external sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this category.
(c) "Prices Based on Models and other valuation Methods" contain the following: the value of the Company's adjustments for liquidity and counterparty credit exposure, the value of contracts not quoted by an exchan e or an over-the-countor broker, the value of transactions for which an internally developed price cur'e was developed as a result of the long dated nature of certain transactions, and the value of certain structured transactions.
M-13
We have investments in debt and equity securities which are held in nuclear trust funds. The trust investments and their fair value are discussed in Note 13, "Risk Management, Financial Instruments and Derivatives." Financial instruments in these trust funds have not been included in the market risk calculation for interest rates as these instruments are marked-to-market and changes in market value of these instruments are reflected in a
corresponding decommissioning liability.
Any differences between the trust fund assets and the ultimate liability are expected to be recovered through regulated rates from our regulated customers.
Inflation affects our cost of replacing utility plant and the cost of operating and maintaining plant. The rate-making process limits recovery to the historical cost of assets, resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.
Industry Restructuring In 2000 California's deregulated electricity market suffered problems including high energy prices mainly due to short energy supplies and financial difficulties for retail distribution companies. This energy crisis has highlighted the importance of risk management and has contributed to certain state regulatory and legislative actions which have delayed the start of customer choice and the transition to competitive, market based pricing for retail electricity supply in some of the states in which AEP operates. Seven of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate have enacted restructuring legislation. In general, the legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity.
As legislative and regulatory proceedings
- evolved, six AEP electric operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in five of the seven states that have passed restructuring legislation have discontinued the application of SFAS 71 regulatory accounting for the generation business.
The seven states in various stages of restructuring to transition power generation and supply to market based pricing are Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia.
AEP has not discontinued its regulatory accounting for its subsidiaries doing business in Michigan and Oklahoma pending the effective implementation of the legislation.
Restructuring legislation, the status of the transition plans and the status of the electric utility companies' accounting to comply with the changes in each of AEP's seven state regulatory jurisdictions affected by restructuring legislation is presented in the Note 7 of the Notes to Financial Statements.
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 have provisions for the transfer of functional control of our transmission system to an RTO. Certain AEP subsidiaries are participating in the formation of the Alliance RTO. Other subsidiaries are a member of ERCOT or SPP.
In 2001 the Alliance companies and MISO entered into a settlement addressing transmission pricing and other "seam" issues between the two RTOs.
The FERC subsequently expressed its opinion that four large RTO regions serving the continental US would best support competition and reliability of electric service. Certain state regulatory commissions have taken exception to the FERC's RTO actions.
Louisiana's commission ordered utilities it regulates, including SWEPCo, to show the advantage of large RTOs to their customers.
On December 19, 2001 the FERC approved the proposal of the Midwest ISO for a regional transmission organization and told the Alliance companies, which had submitted a separate RTO proposal, to explore joining the Midwest ISO organization. The FERC's order is intended to facilitate the establishment of a single RTO in the Midwest and to support the establishment of viable, for-profit transmission companies under an RTO umbrella and concluded that the RTO proposed by Alliance companies lacks M-14
sufficient scope to exist as a stand-alone RTO and thus directed the Alliance companies to explore how their business plan can be accommodated within the Midwest ISO.
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's transmission operations or future results of operations and cash flows.
Litigation AEP is involved in various litigation.
The details of significant litigation contin gencies are disclosed in Note 8 and summarized below.
COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo A decision by U.S. District Court for the Southern District of Ohio in February 2001 that denied AEP's deduction of interest claimed on AEP's consolidated federal income tax returns related to its COLI program resulted in a $319 million reduction in net income for 2000. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 for APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets on AEP's balance sheet and other property and investments on the subsidiaries' balance sheets pending the resolution of this matter.
AEP has appealed the Court's decision.
The earnings reductions for affected registrant subsidiaries are as follows:
(in millions)
APCo
$ 82 CSPCo I&M KPCo OPCo Shareholders' Litigation - Affecting AEP On December 21, 2001, the U.S.
District Court for the Southern District of Ohio dismissed a class action lawsuit against AEP and four former or present officers.
The complaint alleged violation of federal securities laws by disseminating materially false and misleading statements related to the extended Cook Plant outage.
FERC Wholesale Fuel Complaints - Affecting AEP and WTU In November 2001 certain WTU wholesale customers filed a complaint with FERC alleging that WTU has overcharged them since 1997 through the fuel adjustment clause. The customers allege inappropriate costs related to purchased power were included in the fuel adjustment clause.
Management is working to compute if any overcharges occurred and is unable to predict their impact on results of operations, cash flow and financial condition.
Municipal Franchise Fee Litigation - Affecting AEP and CPL In 2001 CPL paid $11 million to settle class action litigation regarding municipal franchise fees in Texas.
The City of San Juan, Texas had filed a class action lawsuit in 1996 seeking $300 million in damages.
Texas Base Rate Litigation - Affecting AEP and CPL In 2001 the Texas Supreme Court denied CPL's request for the court to review a 1997 PUCT base rate order. Subsequently the Court also denied CPL's rehearing request.
The primary Issues CPL requested the Court to review were:
the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; and an $18 million disallowance of affiliated service billings.
41 66 8
118 M-15
Lignite Mining Agreement Litigation Affecting AEP and SWEPCo In 2001 SWEPCo settled litigation concerning lignite mining in Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves.
SWEPCo and CLECO, an unaffiliated utility, are each a 50%
owner of the Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine operator's interest in the mining operations and related debt and other obligations for $86 million.
Merger Litigation -
Affecting AEP and all Subsidiary Registrants In January 2002, a federal court 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.
Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.
Other - Affecting AEP and all Subsidiary Registrants AEP and its registrant 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 the results of operations, cash flows or financial condition.
Environmental Concerns and Issues The U.S. continues to debate an array of environmental issues affecting the electric utility industry including new emission limitations recommended by the Bush Administration in February 2002. Most of the policies are aimed at reducing air emissions citing alleged impacts of such emissions on public health, sensitive ecosystems or the global climate.
AEP and its subsidiaries' policy on the environment continues to be the development and application of long-term economically feasible measures to improve air and water quality, limit emissions and protect the health of employees, customers, neighbors and others impacted by their operations.
In support of this policy, AEP and its subsidiaries continue to invest in research through groups like the Electric Power Research Institute and directly through demonstration projects for new technology for the capture and storage of carbon dioxide, mercury, NOx and other emissions.
The AEP System intends to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices.
AEP and its subsidiaries have a proven record of efficiently producing and delivering electricity and gas while minimizing the impact on the environment. AEP and its subsidiaries have spent billions of dollars to equip their facilities with the latest cost effective clean air and water technologies and to research new technologies. We are proud of our award winning efforts to reclaim our mining properties.
The introduction of multi-pollutant control legislation is being discussed by members of Congress and the Bush Administration.
The legislation being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and other emissions from electric generating plants.
Management will continue to support solutions which are based on sound science, economics and demonstrated control technologies. Management is unable to predict the timing or magnitude of additional pollution control laws or regulations.
If additional control technology is required on facilities owned by the electric utility companies and their costs were not recoverable from ratepayers or through market based prices or volumes of product sold, they could adversely affect future results of operations and cash flows. The following discussions explains existing control efforts, litigation and other pending matters related to environmental issues for AEP companies.
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Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M and OPCo Since 1999 AEP, APCo, CSPCo, I&M and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA, a number of states and certain special interest grups alleged that APCo, CSPCo, I&M and OPCo modified certain generating units over a 20 year period in violation of the Clean Air Act.
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. We believe our maintenance, repair and replacement activities were in conformity with the Clean Air Act and intend to vigorously pursue our defense.
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 March 2001 the District Court ruled that 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 is unable to estimate a loss or predict the timing of the resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition.
An unaffiliated utility which operates certain plants jointly owned by CSPCo reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act.
Negotiations are continuing and a settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows.
NOx Reduction - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a NOx rule (the Nox Rule) and granted petitions filed by certain northeastern states (the Section 126 Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located.
Federal EPA ruled that eleven states, including certain states in which AEP's generating units are located, failed to submit approvable plans to comply with the NOx Rule. This ruling means that those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. A request for the D.C. Circuit Court to review this ruling is pending. The compliance date for the NOx Rule is May 31, 2004.
The D.C.
Circuit Court instructed Federal EPA to justify methods used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule.
In response to AEP and other utilities request for the D.C. Circuit Court to suspend the May 2003 compliance date of the Section 126 Rule, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand.
In April 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo.
In 2001 selective catalytic reduction (SCR) techr ology to reduce NOx emissions on OPCo's Gavin Plant commenced operation. Construction of SCR technology at certain othe generating units continues with M-17
completion scheduled in 2002 through 2006.
Our estimates indicate that compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion of which approximately $450 million has been spent for the AEP System.
The following table shows the estimated compliance cost and amounts spent for certain of AEP's registrant subsidiaries.
Company APCo CPL I&M OPCo SWEPCo Estimated Amounts Compliance Costs Spent (in millions)
$365 57 202 606 28
$130 4
277 21 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 future results of operations, cash flows and possibly financial condition.
Superfund -
Affecting AEP, APCo, CPL, CSPCo, I&M, OPCo and SWEPCo By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.
Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized.
In
- addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and non hazardous materials.
We are currently incurring costs to safely dispose of these substances.
Additional costs could be incurred to comply with new laws and regulations if enacted.
Superfund addresses clean-up of hazardous substances at disposal sites and authorized Federal EPA to administer the clean-up programs. As of year-end 2001, subsidiaries of AEP have been named by the Federal EPA as a PRP for five sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are four additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo have received information requests which could lead to PRP designation. CPL, OPCo and SWEPCo have also been named a PRP at two sites under state law. Our liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where AEP or its subsidiaries have been named a PRP or defendant, their disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.
While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding AEP's and its subsidiaries' potential future liability.
Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous.
Although liability is joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. If significant cleanup costs are attributed to AEP or its subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers.
Global Climate Change - Affecting AEP and all Registrant Subsidiaries At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160 countries, including the U.S.,
negotiated a treaty requiring legally-binding reductions in M-18
emissions of greenhouse gases, chiefly carbon dioxide, which many scientists believe are contributing to global climate change.
Although the U.S. signed the Kyoto Protocol on November 12, 1998, the treaty was not submitted to the Senate for its advice and consent by President Clinton. In March 2001 President Bush announced his opposition to the treaty and its U.S. ratification.
At the Seventh Conference of the Parties in November 2001, the parties finalized the rules, procedures and guidelines required to facilitate ratification of the protocol.
The protocol is expected to become effective by 2003.
U.S. representatives attended the Seventh Conference but they did not take any positions on issues being negotiated or attempt to block the approval of any issue.
AEP does not support the Kyoto Protocol but intends to work with the Bush Administration and U.S. Congress to develop responsible public policy on this issue.
Management expects due to President Bush's opposition to legislation mandating greenhouse gas emissions controls, any policies developed and implemented in the near future are likely to encourage voluntary measures to reduce, avoid or sequester such emissions.
The acquisition of 4,000 MW of coal fired generation in the United Kingdom in December 2001 exposes these assets to potential carbon dioxide emission control obligations since the U.K. is expected to be a party to the Kyoto Protocol.
Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, CPL and I&M I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants.
The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law CPL and I&M participate in the DOE's SNF disposal program which is described in Note 8 of the Notes to Financial Statements. Since 1983 I&M has collected
$288 million from customers for the disposal of nuclear fuel consumed at the Cook Plant.
$116 million of these funds have been deposited in external trust funds to provide for the future disposal of SNF and $172 million has been remitted to the DOE.
CPL has collected and remitted to the DOE, $49 million for the futur e disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date DOE has failed to comply with the requirements of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number of unaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C.
Circuit Court order DOE to meet its obligations tinder the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal.
DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities.
In August 2000, in an appeal of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standarcd contract between utilities and the DOE did not apply to DOE's complete failure to perform Its contract obligations, and that the utilities' suits against DOE may continue in court. AEP's and I&M's suit has been stayed pending further action by the U.S. Court of Federal Claims. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage and the cost of debommissioning will continue to increase.
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In January 2001, I&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.
The settlement allows PECO to skip two payments to the DOE for disposal of SNF due to the lack of progress towards development of a permanent repository for SNF.
The companies believe the settlement is unlawful as the settlement would force other utilities to make up any shortfall in DOE's SNF disposal funds.
The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF 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,
- 2001, the total decom missioning trust fund balance for Cook Plant was $598 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate CPL'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, 2001, the total decommission ing trust fund for CPL's share of STP was $99 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.
We will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP.
However, AEP's, CPL's and I&M'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.
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 M-20 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.
- 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. Through December 31, 2001 we have invested approximately $40 million in this effort. If the required regulatory approvals are not obtained and the line is not constructed, the $40 million investment would be written off adversely affecting AEP's and APCo's future results of operations and cash flows.
OTHER MATTERS Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo At the 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 from Enron and entered into a lease arrangement with a subsidiary of Enron for a gas storage facility.
At the date of Enron's bankruptcy various HPL related contingencies and indemnities remained unsettled. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated losses from the Enron bankruptcy.
The amounts for certain subsidiary registrants were:
Registrant APCo CSPCo I&M KPCo OPCo Amounts Provided (in
$5.2 3.2 3.4 1.3 4.3 Amounts Net of Tax millions) 3.4 2.1 2.2 0.8 2.8
The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceedings, our future results of operations, cash flows and possibly financial condition could be adversely impacted.
International Investments - Affecting AEP We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we 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 our investment has been affected by the devaluation of the Brazilian Real.
The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2000 is approximately $33 million and $49 million, respectively net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price.
As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option.
Management has evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and has concluded that our partners should be able to fulfill their responsibilities.
Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered.
Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations.
Management will continue to monitor both the status of the losses and the ability of its partners to fulfill their obligations under the put.
Investments Limitations - Affecting AEP 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, 2001, AEP's investment in EWGs and FUCOs was $2.9 billion, including guarantees of debt, compared to AEP's limit of $3.3 billion.
SEC rules under PUHCA permit AEP to invest up to 15% of consolidated capitalization (such amount was $3.6 billion at December 31, 2001) in energy-related companies, including marketing and/or trading of electricity, gas and other energy commodities.
Our gas trading business and our interest in domestic cogeneration projects are reported as investments under this rule and at December 31, 2001, such investment was
$2.2 billion.
New Accounting Standards - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU The FASB recently issued SFAS 141, "Business Combinations" and SFAS 142, "Goodwill A d Other Intangible Assets." SFAS 141 requires that the purchase method of accounting be used to account for all business combinations entered into after June 30, 2001.
SFAS 142 requires that goodwill M-21
amortization cease and that goodwill and other intangible assets with indefinite lives be tested for impairment upon SFAS 142 implementation and annually thereafter. We must implement these new standards in the first quarter of 2002. Amortization of goodwill and other intangible assets with indefinite lives will cease with our implementation of SFAS 142 beginning January 1, 2002. The amortization of goodwill reduced AEP's net income by $50 million for the twelve months ended December 31, 2001. The registrant subsidiaries did not have any goodwill at December 31, 2001. We are currently in the process of fair valuing our reporting units with goodwill in order to determined potential goodwill impairment. As such we have not yet determined the impact on first quarter 2002 results of operations of adopting the provision of these standards.
SFAS 143, "Accounting for Asset Retirement Obligations," will become effective for us beginning January 1, 2003. SFAS 143 established accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. We are currently in the process of evaluating the provisions of the standard and determining its impact on future results of operations and financial condition.
To the extent AEP or it registrant subsidiaries are regulated entities, we anticipate that the cumulative effect of this accounting change on future results of operations will be significantly offset by a regulatory asset representing the right to recover legal asset retirement obligations (ARO) relative to regulated long lived assets included in rate base.
The impact on future results of operations from the implementation of this new standard on non-regulated long lived assets has not yet been determined.
We anticipate that the considerable effort to identify all long lived assets with legal ARO and to determine the required discounted legal ARO will take the remainder of 2002.
In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets" which sets forth the accounting to recognize and measure an impairment loss. This standard replaces the previous standard, SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be Disposed Of." SFAS 144 will apply to us beginning January 1, 2002. We do not expect that the imple mentation of SFAS 144 will materially affect results of operations or financial condition.
The FASB recently revised its prior guidance related to SFAS 133, "Accounting for Deriviative Instruments and Hedging Activities" with regard to certain power option and forward contracts. The revised guidance states that power contracts, including both forward and option contracts, that include certain qualitative characteristics are considered capacity contracts, and qualify for the normal purchases and normal sales exception from being marked to market even if they are subject to being booked out, or scheduled to be booked out.
As normal purchases and sales these open energy contracts are not marked to market. Rather they are accounted for on a settlement basis.
Most of AEP's power contracts that are not marked to market as trading transactions do not qualify as derivatives and thus are not subject to the revised guidance.
The few contracts that are derivatives qualified for the exception under the previous guidance and will continue to qualify under the new guidance.
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Common stock and Dividend Information The quarterly high and low sales prices for AEP common stock and the cash divi ends paid per share are shown in the following table:
Quarter Ended High Low Dividend March 2001
$48.10
$39.25
$0.60 june 2001 51.20 45.10 0.60 september 2001 48.90 41.50 0.60 December 2001 46.95 39.70 0.60 March 2000 34.94 25.94 0.60 June 2000 38.50 29.44 0.60 September 2000 40.00 29.94 0.60 December 2000 48.94 36.19 0.60 AEP common stock is traded principally on the New York stock Exchange.
At December 31, 2001, AEP had approximately 150,000 shareholders of record.
ATTACHMENT 2 TO AEP:NRC:2691-11 INDIANA MICHIGAN POWER COMPANY PROJECTED CASH FLOW FOR THE YEAR 2002
2002 Forecasted Internal Cash Flow
$ Millions Net income After Taxes Less: Dividends 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 2002 117.4 4.5 112.9 169.8 85.6 (41.3)
(2.2)
(45.5) 166.4 279.3 69.8 0.5 70.3