UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
February 25, 2003
(Date of earliest
event reported)
Commission File Name of Registrant; State of Incorporation; Address of IRS Employer
Number Principle Executive Offices; and Telephone Number Identification Number
--------------- ------------------------------------------------------ ---------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza
Columbus, Ohio 43215-2373
Telephone (614)223-1000
Item 5. Other Events
The purpose of the Current Report is to file certain financial information
regarding American Electric Power Company, Inc. and Subsidiary Companies.
Such financial information is set forth in the exhibits to this Current Report.
Item 7. Financial Statements and Exhibits
(c) Exhibits
23 Consent of Deloitte & Touche LLP
99 American Electric Power 2002 Annual Report - Audited Consolidated Financial
Statements and Management's Discussion and Analysis
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
American Electric Power Company, Inc.
By: /s/Joseph M. Buonaiuto
----------------------------
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: February 25, 2003
Exhibit 23 - Consent of Deloitte & Touche LLP
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
333-46360, 333-39402, 333-66048, and 333-62278 of American Electric Power
Company, Inc. on Form S-8, Post-Effective Amendment No. 1 to Registration
Statement No. 333-50109 of American Electric Power Company, Inc. on Form S-8,
Post-Effective Amendment No. 3 to Registration Statement No. 33-01052 of
American Electric Power Company, Inc. on Form S-8, Post-Effective Amendment
No. 3 to Registration Statement No. 33-01734 of American Electric Power
Company, Inc. on Form S-3, Registration Statement Nos. 333-58540 and 333-86050
of American Electric Power Company, Inc. on Form S-3, of our report dated
February 21, 2003, appearing in this Current Report on Form 8-K of American
Electric Power Company, Inc. for the year ended December 31, 2002.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 25, 2003
Exhibit 99 - American Electric Power 2002 Annual Report - Audited Consolidated
Financial Statements and Management's Discussion and Analysis
American Electric Power
2002 Annual Report
Audited Consolidated Financial Statements and
Management's Discussion and Analysis
AMERICAN ELECTRIC POWER
1 Riverside Plaza
Columbus, Ohio 43215-2373
CONTENTS
Common Stock and Dividend Information
Glossary of Terms
Forward Looking Information
Selected Consolidated Financial Data
Management's Discussion and Analysis of Results of Operations and Financial
Condition
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income
Notes to Consolidated Financial Statements
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
Schedule of Consolidated Long-term Debt of Subsidiaries
Management's Responsibility
Independent Auditors' Report
Common Stock and Dividend Information
The quarterly high and low sales prices and the quarter-end closing price for
AEP common stock and the cash dividends paid per share are shown in the
following table:
Quarter-end
Quarter Ended High Low Closing Price Dividend
March 2002 $47.08 $39.70 $46.09 $0.60
June 2002 48.80 39.00 40.02 0.60
September 2002 40.37 22.74 28.51 0.60
December 2002 30.55 15.10 27.33 0.60
March 2001 $48.10 $39.25 $47.00 $0.60
June 2001 51.20 45.10 46.17 0.60
September 2001 48.90 41.50 43.23 0.60
December 2001 46.95 39.70 43.53 0.60
AEP common stock is traded principally on the New York Stock Exchange. At
December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003
management recommended that the Company reduce dividends by approximately 40%
after payment of the March 2003 dividend which was approved by the Company's
Board of Directors at the current level of $0.60 per share.
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
Term Meaning
2004 True-up Proceeding............A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount
of stranded costs and the recovery of such costs.
AEGCo..............................AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................American Electric Power Company, Inc.
AEP Consolidated...................AEP and its majority owned consolidated subsidiaries.
AEP Credit.........................AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East companies.................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR...............................AEP Resources, Inc.
AEP System or the System...........The American Electric Power System, an integrated electric utility system, owned and operated
by AEP's electric utility subsidiaries.
AEPSC..............................American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool.....................AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West companies.................PSO, SWEPCo, TCC and TNC.
AFUDC..............................Allowance for funds used during construction, a noncash nonoperating income item
that is capitalized and recovered through depreciation over the service life of
domestic regulated electric utility plant.
Alliance RTO.......................Alliance Regional Transmission Organizatiion, an ISO formed by AEP and four unaffiliated
utilities (the FERC overturned earlier approvals of this RTO in December 2001).
Amos Plant.........................John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo...............................Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................Arkansas Public Service Commission.
Buckeye............................Buckeye Power, Inc., an unaffiliated corporation.
CLECO..............................Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI...............................Corporate owned life insurance program.
Cook Plant.........................The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................Central Power and Light Company [legal name changed to AEP Texas Central
Company (TCC) effective December 2002]. See TCC.
CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW................................Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the
legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Energy.........................CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International..................CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court.................The United States Court of Appeals for the District of Columbia Circuit.
DHMV...............................Dolet Hills Mining Venture.
DOE................................United States Department of Energy.
ECOM...............................Excess Cost Over Market.
ENEC...............................Expanded Net Energy Costs.
EITF...............................The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT..............................The Electric Reliability Council of Texas.
EWGs...............................Exempt Wholesale Generators.
FASB...............................Financial Accounting Standards Board.
Federal EPA........................United States Environmental Protection Agency.
FERC...............................Federal Energy Regulatory Commission.
FMB ...............................First Mortgage 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.
MISO...............................Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR................................Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool.........................AEP System's Money Pool.
MPSC...............................Michigan Public Service Commission.
MTM................................Mark-to-Market.
MTN................................Medium Term Notes.
MW.................................Megawatt.
MWH................................Megawatthour.
NEIL...............................Nuclear Electric Insurance Limited.
NOx................................Nitrogen oxide.
NOx Rule...........................A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies operate.
NP.................................Notes Payable.
NRC................................Nuclear Regulatory Commission.
Ohio Act...........................The Ohio Electric Restructuring Act of 1999.
Ohio EPA...........................Ohio Environmental Protection Agency.
OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary.
OVEC...............................Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a
44.2% equity interest.
PCBs...............................Polychlorinated Biphenyls.
PJM................................Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP.............................. Potentially Responsible Party.
PSO................................Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO...............................The Public Utilities Commission of Ohio.
PUCT...............................The Public Utility Commission of Texas.
PUHCA..............................Public Utility Holding Company Act of 1935, as amended.
PURPA..............................The Public Utility Regulatory Policies Act of 1978.
RCRA...............................Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
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 Types of Regulation.
---------------------------------------------------------
SFAS 101...........................Statement of Financial Accounting Standards No. 101,
Accounting for the Discontinuance of Application of Statement 71.
----------------------------------------------------------------
SFAS 133...........................Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
------------------------------------------------------------
SNF................................Spent Nuclear Fuel.
SPP................................Southwest Power Pool.
STP................................South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC.............................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
Power and Light Company (CPL)].
Texas Appeals Court................The Third District of Texas Court of Appeals.
Texas Legislation..................Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
Utilities Company (WTU)].
Travis District Court..............State District Court of Travis County, Texas.
TVA ...............................Tennessee Valley Authority.
U.K................................The United Kingdom.
UN.................................Unsecured Note.
VaR................................Value at Risk, a method to quantify risk exposure.
Virginia SCC.......................Virginia State Corporation Commission.
WV.................................West Virginia.
WVPSC..............................Public Service Commission of West Virginia.
WPCo...............................Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective
December 2002]. See TNC.
Yorkshire..........................Yorkshire Electricity Group 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.
FORWARD LOOKING INFORMATION
This report made by AEP contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP
believes that its expectations are based on reasonable assumptions, any
such statements may be influenced by factors that could cause actual
outcomes and results to be materially different from those projected. Among
the factors that could cause actual results to differ materially from those
in the forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our service
territories.
o The ability to recover stranded costs in connection with
possible/proposed deregulation.
o New legislation and government regulation.
o Oversight and/or investigation of the energy sector or its
participants.
o The ability of AEP to successfully control its costs.
o The success of acquiring new business ventures and disposing of
existing investments that no longer match our corporate profile.
o International and country-specific developments affecting AEP's foreign
investments including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in AEP's service territory and
changes in market demand and demographic patterns.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates.
o Liquidity in the banking, capital and wholesale power markets.
o Actions of rating agencies.
o Changes in technology, including the increased use of distributed
generation within our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data
Year Ended December 31, 2002 2001 2000 1999 1998
----------------------- ---- ---- ---- ---- ----
OPERATIONS STATEMENTS DATA (in millions):
Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080
Operating Income 1,263 2,182 1,774 2,061 2,046
Income Before Discontinued Operations, Extraordinary
Items and Cumulative Effect 21 917 180 869 859
Discontinued Operations Income (Loss) (190) 86 122 117 116
Extraordinary Losses - (50) (35) (14) -
Cumulative Effect of
Accounting Change Gain (Loss) (350) 18 - - -
Net Income (Loss) (519) 971 267 972 975
December 31, 2002 2001 2000 1999 1998
------------ ---- ---- ---- ---- ----
BALANCE SHEET DATA (in millions):
Property, Plant and Equipment $37,857 $37,414 $34,895 $33,930 $32,400
Accumulated Depreciation
and Amortization 16,173 15,310 14,899 14,266 13,374
------- ------- ------- ------- -------
Net Property,
Plant and Equipment $21,684 $22,104 $19,996 $19,664 $19,026
======= ======= ======= ======= =======
Total Assets $34,741 $39,297 $46,633 $35,296 $33,418
Common Shareholders' Equity 7,064 8,229 8,054 8,673 8,452
Cumulative Preferred Stocks
of Subsidiaries* 145 156 161 182 350
Trust Preferred Securities 321 321 334 335 335
Long-term Debt* 10,496 9,505 8,980 9,471 9,215
Obligations Under Capital Leases* 228 451 614 610 539
Year Ended December 31, 2002 2001 2000 1999 1998
----------------------- ---- ---- ---- ---- ----
COMMON STOCK DATA:
Earnings per Common Share:
Before Discontinued Operations, Extraordinary
Items and Cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70
Discontinued Operations (0.57) 0.26 0.38 0.36 0.36
Extraordinary Losses - (0.16) (0.11) (0.04) -
Cumulative Effect of
Accounting Change (1.06) 0.06 - - -
------- ------ ------ ------ -----
Earnings (Loss) Per Share $ (1.57) $ 3.01 $ 0.83 $ 3.03 $3.06
======= ====== ====== ====== =====
Average Number of Shares
Outstanding (in millions) 332 322 322 321 318
Market Price Range:
High $ 48.80 $51.20 $48-15/16 $48-3/16 $53-5/16
Low 15.10 39.25 25-15/16 30-9/16 42-1/16
Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16
Cash Dividends on Common** $ 2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%
Book Value per Share $20.85 $25.54 $25.01 $26.96 $26.46
*Including portion due within one year. Long-term Debt includes Equity Unit Senior Notes.
**Based on AEP historical dividend rate. See "Common Stock and Dividend
Information" on page 2 regarding the potential reduction of future dividends.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations and Financial
Condition
American Electric Power Company, Inc. (AEP or the Company) is one of the largest
investor owned electric public utility holding companies in the U.S. We provide
generation, transmission and distribution service to almost five million retail
customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our
electric utility operating companies.
We have a vast portfolio of assets including:
o 38,000 megawatts of generating capacity, the largest complement of
generation in the U.S., the majority of which has a significant cost
advantage in our market areas
o 4,000 megawatts of generating capacity in the U.K., a country which
is currently experiencing excess generation capacity
o 38,000 miles of transmission lines, the backbone of the electric
interconnection grid in the Eastern U.S.
o 186,000 miles of distribution lines that support delivery of
electricity to our customers' premises
o Substantial coal transportation assets (7,000 railcars, 1,800 barges,
37 tug boats and two coal handling terminals with 20 million tons of
annual capacity)
o 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of
gas storage facilities
Business Strategy
We plan to focus on utility operations in the U.S. We continue to participate in
wholesale electricity and natural gas markets. Weakness in these markets after
the collapse of Enron and other companies caused us to re-examine and realign
our strategy to direct our attention to our utility markets. We have reduced
trading to focus predominantly in markets where we have assets. We plan to
obtain maximum value for our assets by selling excess output and procuring
economical energy using commercial
expertise gained from our extensive experience in the wholesale business.
Through our utility operations focus, we intend to be the energy and low cost
generation provider of choice. We have ample generation to meet our customers'
needs. We have a cost advantage resulting from AEP's long tradition of
designing, building and operating efficient power plants and delivery networks.
Our customers continue to show top quartile level of satisfaction. We provide
safe and reliable sources of energy.
Our business provides a vital requirement of our economy and affords an
opportunity for a fair return to our shareholders. Our business provides the
opportunity for a predictable stream of cash flows and earnings, allowing us to
pay a competitive dividend to investors.
We are addressing many challenges in our unregulated business. We have already
substantially reduced our trading activities. We have written down the value of
several investments to reflect deterioration in market conditions. We are
evaluating our portfolio and plan to sell assets that are no longer core to our
business strategy. We are also in discussion with our regulators to determine if
the legal separation of certain operating company subsidiaries into regulated
and unregulated segments can be avoided. We believe that the expected benefits
from legal separation are no longer compelling. Transition rules for Michigan
and Virginia do not require legal separation. Deregulation is no longer an
expectation in the foreseeable future in the other states where we operate.
Our strategy for the core business of utility operations is to:
o Maintain moderate but steady earnings growth
o Maximize value of transmission assets and protect our revenue stream
in an RTO membership environment
o Continue process improvement to maintain distribution service quality
while, at the same time, further enhancing financial performance
o Optimize generation assets through increased availability and sale of
excess capacity
o Manage the regulatory process to maximize retention of earnings
improvement while providing fair and reasonable rates to our customers
We remain very focused on credit quality and liquidity as discussed in greater
detail later in this report.
We are committed to continually evaluating the need to reallocate resources to
areas with greater potential, to match investments with our strategy and to pare
investments that do not produce sufficient return and sustainable shareholder
value. Any investment dispositions could affect future results of operations,
cash flows and possibly financial condition.
2002 Overview
2002 was a year of rapid and dramatic change for the energy industry, including
AEP, as the wholesale energy market quickly shrank and many of its participants
exited or significantly limited future trading activity. Investors lost
confidence in corporate America and the economy stalled. Investors' demand for
stability, predictable cash flows, earnings, and financial strength have
replaced their demand for rapid growth.
Our wholesale business did not perform well. We had significant losses in
options trading in the first half of the year and new investments performed well
below our expectations.
We focused on financial strength by:
o Issuing approximately $1 billion in common stock and equity units
o Retiring debt of approximately $3 billion through the sale of two
foreign retail utility companies in the U.K. (SEEBOARD) and
Australia (CitiPower)
o Establishing a cash liquidity reserve of $1 billion at year-end
See the Financing Activity section for an overview of all changes to
capital structure.
We also focused on:
o Implementing an enterprise-wide risk management system
o Completing a cost reduction initiative which we expect to result in
sustainable net annual savings of more than $200 million beginning in
2003
o Eliminating or reducing future capital requirements associated with
non-core assets
We have redirected our business strategy by:
o Scaling back trading activities to focus principally on supporting our
core assets
o Selling our Texas retail business
o Proposing the sale of a significant portion of the Texas unregulated
generation assets
Outlook for 2003
We remain focused on the fundamental earnings power of our utility operations,
and we are committed to strengthening our balance sheet. Our strategy for
achieving these goals is well planned:
o First, we will continue to identify opportunities to reduce our
operations and maintenance expense.
o Second, we will find opportunities to reduce capital expenditures.
o Third, management recommended a 40% reduction in the common stock
dividend beginning in the second quarter to a quarterly rate of $0.35
per share. This will result in annual cash savings of approximately
$340 million and should improve our retained earnings as well as create
free cash flow to improve liquidity and pay-down outstanding debt.
o Fourth, we plan to evaluate and, where appropriate, dispose of non-core
assets. Proceeds from these sales will be used to reduce debt.
o Fifth, we will continue to evaluate the potential for issuing
additional equity to further strengthen our balance sheet and maintain
credit quality.
We remain committed to being a low cost provider of electricity, to serving our
customers with excellence and to providing an attractive return to investors. We
will therefore focus on producing the best possible results from our utility
operations enhanced by a commercial group that ensures maximum value from our
assets.
Although we aim for excellent results of operations there are challenges and
certain risks. We discuss these matters in detail in the Notes to Consolidated
Financial Statements and in this Management's Discussion and Analysis. We will
work diligently to resolve these matters by finding workable solutions that
balance the interests of our customers, our employees and our investors.
Results of Operations
In 2002 AEP's principal operating business segments and their major activities
were:
o Wholesale:
o Generation of electricity for sale to retail and wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas, coal and other commodities
o Coal mining, bulk commodity barging operations and other energy supply
related businesses
o Energy Delivery
o Domestic electricity trans-mission
o Domestic electricity distri-bution
o Other Investments
o Energy services
Net Income
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001.
The Company recognized impairments on under-performing assets and recorded
losses in value of $854 million (net of tax) (see Note 13). The losses in the
fourth quarter 2002 were generally caused by the extended decline in domestic
and international wholesale energy markets and in telecommunications. In 2002
the Company's Net Loss was $519 million or a loss of $1.57 per share including
the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss
for transitional goodwill impairment related to SEEBOARD and CitiPower that
resulted from the adoption of SFAS 142 (see Note 3).
Net Income increased in 2001 to $971 million or $3.01 per share from $267
million or $0.83 per share in 2000. The increase of $704 million or $2.18 per
share was due to the growth of AEP's wholesale marketing business, increased
revenues and the controlling of our operating and maintenance costs in the
energy delivery business, and declining capital costs. The effect of 2000
charges for a disallowance of COLI-related tax deductions, expenses of the
merger with CSW, write-offs related to non-regulated investments and restart
costs of the Cook Nuclear Plant were all contributing factors to the increase in
2001 earnings compared to 2000. The favorable effect on comparative Net Income
of these 2000 charges was offset in part in 2001 by losses from Enron's
bankruptcy and extraordinary losses for the effects of deregulation and a loss
on reacquired debt.
Our wholesale business has been affected by a slowing economy. Wholesale energy
margins and energy use by industrial customers declined in 2002 and 2001.
Earnings from our wholesale business, which includes generation, increased in
2001 largely as a result of the successfull return to service of the Cook Plant
in June 2000 and by acquisitions of HPL and MEMCO.
Our energy delivery business, which consists of domestic electricity
transmission and distribution services, contributed to the increase in earnings
by controlling operating and maintenance expenses and by increasing revenues in
2002 and 2001.
Capital costs decreased due primarily to interest paid to the IRS in 2000 on a
COLI deduction disallowance and continuing declines in short-term market
interest rate conditions since early 2001.
Volatility in energy commodities markets affects the fair values of all of our
open trading and derivative contracts exposing AEP to market risk and causing
our results of operations to be more volatile. See "Market Risks" section for a
discussion of the policies and procedures AEP uses to manage its exposure to
market and other risks from trading activities.
Revenues Increase
AEP's total revenues increased 14% in 2002 and 15% in 2001. The following table
shows the components of revenues:
For The Year Ended
December 31
2002 2001 2000
(in millions)
WHOLESALE:
Residential $3,713 $ 3,553 $ 3,511
Commercial 2,156 2,328 2,249
Industrial 1,903 2,388 2,444
Other Retail
Customers 385 419 414
Electricity
Marketing (net) 2,227 802 1,073
Unrealized MTM
Income-Electric 136 210 38
Other 1,397 632 837
Less Transmission and
Distribution Revenues
Assigned to Energy
Delivery* (3,551) (3,356) (3,174)
------ ------- -------
Wholesale
Electric 8,366 6,976 7,392
------ ------- -------
Gas Marketing (net) 3,021 2,274 310
Unrealized MTM Income
(Loss)-Gas (399) 47 132
------- ------- -------
Wholesale Gas 2,622 2,321 442
------- ------- -------
TOTAL WHOLESALE 10,988 9,297 7,834
------- ------- -------
DOMESTIC ELECTRICITY
DELIVERY:
Transmission 922 1,029 1,009
Distribution 2,629 2,327 2,165
------- ------- -------
TOTAL DOMESTIC
ELECTRICITY
DELIVERY 3,551 3,356 3,174
------- ------- -------
OTHER
INVESTMENTS 16 114 105
------- ------- -------
TOTAL REVENUES $14,555 $12,767 $11,113
======= ======= =======
*Certain revenues in Wholesale business include energy delivery revenues due
primarily to bundled tariffs that are assignable to the Energy Delivery
business.
The level of electricity transactions tends to fluctuate due to the highly
competitive nature of the short-term (spot) energy market and other factors,
such as affiliated and unaffiliated generating plant availability, weather
conditions and the economy. The FERC's introduction of a greater degree of
competition into the wholesale energy market has had a major effect on the
volume of wholesale power marketing especially in the short-term market. The
increase in 2002 in wholesale revenues resulted from a 27% increase in trading
volume associated with Wholesale Electricity which was offset by a continuing
decrease in gross margins which began in the fourth quarter of 2001, and an
increase in residential sales as a result of favorable weather conditions in the
third quarter 2002. In addition Other wholesale electric revenues increased due
to the mid-year 2001 acquisition of barging and coal mining operations as well
as the recognition of revenues for generation projects completed for third
parties. The increase in 2002 Wholesale Gas revenues resulted from a full year
of HPL operations compared to a partial year from our acquisition date in July
2001, offset by a decrease in the results from financial trading and MTM
unrealized losses. Other Investments decreased in 2002 due to the elimination of
factoring of accounts receivable of an unaffiliated utility.
Prior to the third quarter of 2002, we recorded and reported upon settlement,
sales under forward trading contracts as revenues and purchases under forward
trading contracts as purchased energy expenses. Effective July 1, 2002, we
reclassified such forward trading revenues and purchases on a net basis, as
permitted by EITF 98-10 (see Note 1).
Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in
2001. This decrease was due to the economic slow down which began in late 2001.
Sales to residential customers rose 5% due to weather related demand in 2002.
The economic slow down reduced demand and wholesale prices especially in the
latter part of 2001.
Operating Expenses Increase
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
2002 2001
---- ----
(in millions)
Amount % Amount %
Fuel and Purchased
Energy:
Electricity $ 959 43.7 $(1,275) (36.7)
Gas 404 14.7 2,339 570.5
Maintenance and
Other Operation 303 8.2 228 6.5
Non-recoverable
Merger Costs (11) (52.4) (182) (89.7)
Asset Impairments 867 N.M. - -
Depreciation and
Amortization 134 10.8 152 13.9
Taxes Other Than
Income Taxes 51 7.6 (16) (2.3)
----- ------
Total $2,707 25.6 $1,246 13.3
====== ======
The increase in Fuel and Purchased Energy expense was primarily attributable to
an increase in power generation. Net generation increased 6% for Eastern plants
due to increased demand for electricity and a reduction in planned power plant
maintenance outages for various plants as compared to 2001. The return to
service of the Cook Plant's two nuclear generating units in June 2000 and
December 2000 accounted for the increase in nuclear generation. The increase in
Gas expense was primarily due to a full year of HPL operations compared to a
partial year from our acquisition date in July 2001.
The increase in Maintenance and Other Operation expense in 2002 is primarily due
to recognizing a full year's expense for the businesses acquired during 2001
including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and
HPL. In addition, increased administrative costs for the implementation of
customer choice in Texas contributed to the increase. The increase was offset in
part by a reduction in trading incentive compensation and the effect of planned
boiler plant maintenance at various plants in 2001 and less refueling outages
for STP in 2002 than 2001.
Maintenance and Other Operation expense rose in 2001 mainly as a result of
additional traders' incentive compensation and accruals for severance costs
related to corporate restructuring.
With the consummation of the merger with CSW, certain deferred merger costs were
expensed in 2000. The merger costs charged to expense included transaction and
transition costs not allocable to and recoverable from ratepayers under
regulatory commission approved settlement agreements to share net merger
savings. As expected, merger costs declined in 2001 and 2002 after the merger
was consummated.
In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and
investments totaling $1.4 billion (consisting of approximately, $866.6 million
related to asset impairments, $321.1 million related to investment value losses,
and $238.7 million related to discontinued operations) that reflected downturns
in energy trading markets, projected long-term decreases in electricity prices,
and other factors. These impairments exclude the transitional impairment loss
from adoption of SFAS142 (see Note 2). The categories of impairments included:
2002 Pre-Tax Estimated Loss
(in millions)
Asset Impairments
Held for Sale $ 483.1
Asset Impairments
Held and Used 651.4
Investment Value
Losses 291.9
-------
Total $1,426.4
Additional market deterioration associated with our non-core wholesale
investments, including our U.K. operations, could have an adverse impact on our
future results of operations and cash flows. Significant long-term changes in
external market conditions could lead to additional write-offs and potential
divestitures of our wholesale investments, including, but not limited to, our
U.K. operations.
The rise in Depreciation and Amortization expense in 2002 resulted from the
amortization of Texas generation related Regulatory Assets that were securitized
in early 2002, businesses acquired in 2001 and additional production plant
placed into service.
Depreciation and Amortization expense increased in 2001 primarily as a result of
the 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.
Taxes Other Than Income Taxes increased in 2002 due to a full year of state
excise taxes which replaced the state gross receipts tax in Ohio and increased
local franchise taxes in Texas partly offset by the effect of Texas one-time
2001 assessments and decreased gross Texas receipts taxes due to deregulation.
Interest, Preferred Stock Dividends, Minority Interest
The decrease in Interest in 2002 was primarily due to a reduction in short-term
interest rates and lower outstanding balances of short-term debt and the
refinancing of long-term debt at favorable interest rates offset in part by an
increased amount of long-term debt outstanding.
Interest expense decreased 15% in 2001 due to the effect of interest paid to the
IRS on a COLI deduction disallowance in 2000 and lower average outstanding
short-term debt balances and a decrease in average short-term interest rates.
Minority Interest in Finance Subsidiary increased substantially in 2002 because
the distributions to minority interest were in effect for the entire year. In
2001 we issued a preferred member interest to finance the acquisition of HPL and
paid a preferred return of $13 million to the preferred member interest. The
minority interest was only in effect during the last four months of 2001.
Other Income/Other Expenses
Other Income increased by $110 million or 33% in 2002 due to the sale of AEP'S
retail electric providers in Texas and due to non-operational revenue (see Note
1). Other Expenses increased $134 million or 72% in 2002 due to non-operational
expenses (see Note 1).
Other Income increased $240 million in 2001. This increase was primarily caused
by an increase in equity earnings due to acquisitions of $63 million, a $73
million gain from the sale of a generating plant (see Note 1). Other Expenses
increased by $110 million or 143% in 2001 due to costs to exit air
transportation, fiber optic and Datapult businesses (see Note 1).
Income Taxes
The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book
income offset by the tax effects of the sale of foreign operations.
Although pre-tax book income increased considerably in 2001, Income Taxes
decreased due to the effect of recording in 2000 prior year federal income taxes
as a result of the disallowance of COLI interest deductions by the IRS and
nondeductible merger related costs in 2000.
Extraordinary Losses and Cumulative Effect
The loss for transitional goodwill impairment related to SEEBOARD and CitiPower
resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported
as a Cumulative Effect of Accounting Change on January 1, 2002.
In 2001 we recorded an extraordinary loss of $48 million net of tax to write-off
prepaid Ohio excise taxes stranded by Ohio deregulation. The application of
regulatory accounting for generation was discontinued in 2000 for the Ohio,
Virginia and West Virginia jurisdictions which resulted in the after-tax
extraordinary loss of $35 million.
New accounting rules that became effective in 2001 regarding accounting for
derivatives required us to mark-to-market certain fuel supply contracts that
qualify as financial derivatives. The effect of initially adopting the new rules
at July 1, 2001 was a favorable earnings effect of $18 million, net of tax,
which is reported as a Cumulative Effect of Accounting Change.
Discontinued Operations
The operations shown below were discontinued or held for sale in 2002 (See Note
12). Results of operations including impairment losses, net of tax, of these
businesses have been reclassified:
Company 2002 2001 2000
------- ---- ---- ----
(in millions)
SEEBOARD $ 96 $ 88 $ 99
CitiPower (123) (6) 17
Pushan (7) 4 7
Eastex (156) - (1)
----- ---- ----
$(190) $ 86 $122
===== ==== ====
Reclassification
Balance sheet amounts have been restated to reflect our reclassification of
certain assets and liabilities related to forward physical and financial
transactions (see "Reclassification" discussion in Note 1). Based upon AEP's
legal rights of offset, physical and financial contracts were netted in 2002 and
2001 amounts and financial contracts were netted in 2000 and 1999 amounts.
Related assets and liabilities were not netted in 1998 amounts as the impact is
not material.
Financial Condition
We measure our financial condition by the strength of the Consolidated Balance
Sheets and the liquidity provided by cash flows and earnings.
Balance sheet capitalization ratios and cash flow ratios are principal
determinants of our credit quality.
Credit Ratings
The rating agencies have been conducting credit reviews of AEP and our
registrant subsidiaries. The agencies are also reviewing most companies in the
energy sector due to issues which impact the entire industry, not only AEP and
our subsidiaries.
In February 2003 Moody's Investors Service (Moody's) completed its review of AEP
and our rated subsidiaries. The results of that review were downgrades of the
following ratings for our unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1
to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1.
TNC, which had no senior unsecured notes outstanding at the time of the ratings
action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial
paper was also concurrently downgraded from P-2 to P-3. The completion of this
review was a culmination of earlier ratings action in 2002 that had included a
downgrade of AEP from Baa1 to Baa2 and the placement of five of our registrants
on negative outlook. With the completion of the reviews, Moody's has placed AEP
and it's rated subsidiaries on stable outlook.
In February 2003 Standard & Poor's placed AEP's senior unsecured debt and
commercial paper ratings on credit watch with negative implications, and did the
same with our subsidiaries. S&P indicated that resolution regarding these
actions would come within a short time.
In 2002 Fitch Ratings Service downgraded both PSO and SWEPCo from A to A- for
the senior unsecured notes. Fitch has AEP and our subsidiaries on stable outlook
and the commercial paper rating is stable at F-2.
Current ratings of our subsidiaries' first mortgage bonds are listed in the
following table:
Company Moody's S&P Fitch
APCo Baa1 BBB+ A-
CSPCo A3 BBB+ A
I&M Baa1 BBB+ BBB+
KPCo Baa1 BBB+ BBB+
OPCo A3 BBB+ A-
PSO A3 BBB+ A
SWEPCo A3 BBB+ A
TCC Baa1 BBB+ A
TNC A3 BBB+ A
Current short-term ratings are as follows:
Company Moody's S&P Fitch
AEP P-3 A-2 F-2
The current ratings for senior unsecured debt are listed in the following table:
Company Moody's S&P Fitch
AEP Baa3 BBB+ BBB+
AEP Resources* Baa3 BBB+ BBB+
APCo Baa2 BBB+ BBB+
CSPCo A3 BBB+ A-
I&M Baa2 BBB+ BBB
KPCo Baa2 BBB+ BBB
OPCo A3 BBB+ BBB+
PSO Baa1 BBB+ A-
SWEPCo Baa1 BBB+ A-
TCC Baa2 BBB+ A-
TNC Baa1 BBB+ A-
* The rating is for a series of senior notes issued
with a Support
Agreement from AEP.
AEP's common equity to total capitalization declined to 32% in 2002 from 36% in
2001 and 37% in 2000. Total capitalization includes long-term debt due within
one year, equity unit senior notes, minority interest and short-term debt.
Preferred stock at 1% remained unchanged. In 2002 long-term debt including
equity unit senior notes and trust preferred securities increased from 43% to
50% while Short-term Debt decreased from 17% to 14% and Minority Interest in
Finance Subsidiary remained unchanged at 3%. In 2001 Long-term Debt remained
unchanged while Short-term Debt decreased from 20% to 17% and Minority Interest
in Finance Subsidiary increased to 3%. In 2002, 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. Common stock was
issued in 2002 for stock options exercised and under an equity offering
(discussed in Financing Activity).
Liquidity
Liquidity, or access to cash, has become a more critical factor in determining
the financial stability of the Company due to volatility in wholesale power
markets and the potential limitations that credit rating downgrades place on a
company's ability to raise capital. Management is committed to preserving an
adequate liquidity position and addressing our financial needs in 2003.
As of December 31, 2002, we had an available liquidity position of $3.5 billion
as illustrated in the table below:
Credit Facilities
(in millions) Maturity
Commercial Paper Backup
Lines of Credit $2,500* 5/03
Commercial Paper Backup
Lines of Credit 1,000 5/05
Corporate Separation
Revolving Credit 1,725 4/03
Euro Revolving Credit
Facilities 315 10/03
------
Total 5,540
Cash
Liquidity Reserve 1,000**
Total Credit Facilities
and Cash 6,540
Less: Commercial Paper
Outstanding 1,415
Corporate Separation
Loans 1,300
Euro Revolving
Credit Loans 305
------
Total Available Liquidity $3,520
* Contains one year term-out provision.
** Unrestricted and excludes $213 million
of operational cash on hand.
Our goal for 2003 is to use cash from operations to fund our capital
expenditures, dividend payments and working capital requirements. Short-term
debt is used as an interim bridge for timing differences in the need for cash or
to fund debt maturities until permanent financing is arranged.
Short-term funding comes from the parent company's commercial paper program and
revolving credit facilities. Proceeds are loaned to our subsidiaries through
intercompany notes. We also operate a non-utility and utility money pool to
minimize the AEP System's external short-term funding requirements and sell
accounts receivable to provide liquidity for our domestic electric subsidiaries.
The commercial paper program is backed by $3.5 billion in bank facilities of
which $1 billion matures in May 2005. The remaining $2.5 billion matures in May
2003 and has a one-year term-out provision at our option. At December 31, 2002
approximately $1.4 billion of commercial paper was outstanding. A portion of the
commercial paper balance is related to funding of debt maturities of the Ohio
and Texas subsidiaries pending a permanent financing program. The Ohio and Texas
subsidiaries issued $2,025 million of senior unsecured notes in February 2003
with maturity dates ranging from 2005 to 2033. The commercial paper balance
outstanding decreased in early 2003 due to repayment with proceeds from these
issuances.
AEP also has a $1.725 billion bank facility maturing in April 2003 that is
available for debt refinancing. At December 31, 2002, $1.3 billion was
outstanding under that facility. With the issuance of the permanent financing
for the Ohio and Texas subsidiaries mentioned above, this facility was repaid
and cancelled in February 2003.
We also have revolving credit facilities in place for 300 million Euros to
support the wholesale business in Europe. At December 31, 2002, the majority of
these facilities were drawn.
AEP also maintains a minimum $300 million cash liquidity reserve fund to support
its marketing operations in the U.S. and keeps additional cash on hand as market
conditions change. At December 31, 2002, we had $1 billion of cash available for
liquidity.
On December 6, 2002, we closed a 364-day, $425 million facility and used it to
partially repay the maturing interim financing for the U.K. generation plants
(FFF). The facility was secured by a pledge of the shares of AEP companies in
the FFF ownership chain and guaranteed by the parent company. A portion ($213
million) of the facility is due in May 2003. The remainder of the FFF interim
financing was repaid using a combination of existing funds and draws against the
two Euro revolving credit facilities.
In total, we had approximately $6.5 billion in liquidity sources of which $3.5
billion were unused and available at December 31, 2002.
During 2002, cash flow from operations was approximately $1.7 billion, including
$21 million from Net Income Before Discontinued Operations, Extraordinary Items
and Cumulative Effect, approximately $1.3 billion from depreciation,
amortization, deferred taxes, and deferred investment tax credits, approximately
$1.1 billion associated with asset, investment value and other impairments,
offset by additional working capital requirements of approximately $700 million.
These additional working capital requirements reflect the one time impact of the
discontinuance of the sale of accounts receivable for Texas companies and
billing delays related to the transition to customer choice in Texas, higher
margin requirements for gas trading, seasonal fuel inventory growth, and other
miscellaneous items. Construction expenditures were $1.7 billion including major
expenditures for emission control technology on several coal-fired generating
units (see discussion in Note 9). Dividends on common stock were $793 million.
Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the
Texas REPs and the issuance of common stock, common equity units, 15-year notes
for a wind generation project and transition funding bonds provided funds to
reduce debt, fund construction and pay dividends.
During 2001, AEP's cash flow from operations was $2.8 billion, including $885
million from Net Income Before Discontinued Operations, Extraordinary Items and
Cumulative Effect and $1.4 billion from depreciation, amortization, deferred
taxes and deferred investment tax credits. Capital expenditures including
acquisitions were $3.9 billion and dividends on common stock were $773 million.
Cash from operations less dividends on common stock financed 51% of capital
expenditures.
During 2001, the proceeds of AEP's $1.25 billion global notes issuance and
proceeds from the sale of a U.K. distribution company and two generating plants
provided cash to purchase assets, fund construction, retire debt and pay
dividends. Major construction expenditures include amounts for a wind generating
facility and emission control technology on several coal-fired generating units.
Asset purchases included HPL, coal mines, a barge line, a wind generating
facility and two coal-fired generating plants in the U.K. These acquisitions
accounted for the increase in total debt during 2001. Long-term funding
arrangements for specific assets are often complex and typically not completed
until after the acquisition.
The loss for 2002 resulted in a negative dividend payout ratio of 153%
reflecting the losses on sale and impairments of assets. 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 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, long-term debt, sale-leasebacks and leasing
arrangements. 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.
Our revolving credit agreements include covenants that require us to perform
certain actions, including maintaining specified financial ratios.
Non-performance of these covenants may result in an event of default under these
credit agreements. At December 31, 2002, we complied with the covenants
contained in these credit agreements. In addition, a default under any other
agreement or instrument relating to our debt outstanding in excess of $50
million is an event of default under these credit agreements. An event of
default under these credit agreements would cause all amounts outstanding
thereunder to be immediately payable.
Financing Activity
Common Stock
In June 2002 AEP issued 16 million shares of common stock at $40.90 per share
through an equity offering and received net proceeds of $634 million. Proceeds
from the sale of equity units and common stock were used to pay down short-term
debt and establish a cash liquidity reserve fund.
Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345
million). See Note 27 for additional information.
Debt
In February 2002 TCC issued $797 million of securitization notes that were
approved by the PUCT as part of Texas restructuring to recover generation
related regulatory assets. The proceeds were used to reduce TCC's debt and
equity.
In April 2002 AEP closed on a bridge loan facility consisting of a $1.125
million 364-day revolving credit facility and a $600 million 364-day term loan
facility to prepare for corporate separation. At year-end, $600 million was
borrowed under the term loan facility and $700 million was borrowed under the
revolving credit facility. Those amounts were repaid and the facility terminated
when bonds were issued by CSPCo, OPCo, TCC and TNC in February 2003.
In February 2003 CSPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The use of
proceeds from the above bonds was repayment of the bridge loan facility
mentioned above, repayment of short-term debt, and for general corporate
purposes.
In 2002 the following issuances were completed by the subsidiaries of AEP:
----------------------- -------------------- ----------------------- ----------------------- ----------------
Principal Amount
Company Type of Debt (in millions) Interest Rate Due Date
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Senior Unsecured
APCo Notes $450 4.80% 2005
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Senior Unsecured
APCo Notes 200 4.32%* 2007
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Installment
I&M Purchase Contracts 50 4.90% 2025
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Senior Unsecured
I&M Notes 150 6.0% 2032
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Senior Unsecured
I&M Notes 100 6 3/8% 2012
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
KPCo Senior Unsecured
Notes 125 5.50% 2007
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Senior Unsecured
KPCo Notes 80 4.32%* 2007
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Senior Unsecured
KPCo Notes 70 4.37%* 2007
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
PSO Senior Unsecured
Notes 200 6.00% 2032
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
SWEPCo Senior Unsecured
Notes 200 4.50% 2005
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Other Subsidiaries Notes Payable 121 6.20% - 6.60% 2017
----------------------- -------------------- ----------------------- ----------------------- ----------------
----------------------- -------------------- ----------------------- ----------------------- ----------------
Other Subsidiaries Revolving Credit 305 Variable 2003
----------------------- -------------------- ----------------------- ----------------------- ----------------
-------------------------------------------------------------------------------------------------------------
* Interest rate payable by subsidiary in U.S. dollars. While these companies do
not have an Australian rate obligation, there is an underlying interest rate to
Australian investors in Australian dollars of either 6% or a variable rate.
-------------------------------------------------------------------------------------------------------------
The subsidiaries also redeemed approximately $2 billion of long-term debt in
2002.
AEP uses money pools to meet the short-term borrowings for the majority of its
subsidiaries In addition, AEP also funds the short-term debt requirements of
other subsidiaries that are not included in the money pool. As of December 31,
2002, AEP had credit facilities totaling $3.5 billion to support its commercial
paper program. At December 31, 2002, AEP had $1.4 billion outstanding in
short-term borrowings subject to these credit facilities.
AEP Credit purchases, without recourse, the accounts receivable of most of the
domestic utility operating companies. AEP Credit's financing for the purchase of
receivables changed in December 2001. Starting December 31, 2001, AEP Credit
entered into a sale of receivables agreement. The agreement allows AEP Credit to
sell certain receivables and receive cash meeting the requirements of SFAS 140
for the receivables to be removed from the Consolidated Balance Sheets. At
December 31, 2002, AEP Credit had $454 million sold under this agreement. See
Note 23 for further discussion.
Off-balance Sheet Arrangements
AEP enters into off-balance sheet arrangements for various reasons ranging from
accelerating cash collections, reducing operational expense to spreading risk of
loss to third parties. The following identifies AEP's significant off-balance
sheet arrangements:
Power Generation Facility
AEP has entered into agreements with Katco Funding L.P. (Katco) an unrelated
unconsolidated special purpose entity. Katco has an aggregate financing
commitment of $525 million and a capital structure of which 3% is equity from
investors with no relationship to AEP or any of its subsidiaries and 97% is debt
from a syndicate of banks. Katco was formed to develop, construct, finance and
lease a power generation facility to AEP. Katco will own the power generation
facility and lease it to AEP after construction is completed. The lease will be
accounted for as an operating lease (see Note 22), therefore neither the
facility nor the related obligations are reported on AEP's balance sheet.
Payments under the operating lease are expected to commence in the first quarter
of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW),
which will use the energy produced by the facility and sell excess energy. AEP
has agreed to purchase the excess energy from DOW for resale. The use of Katco
allows AEP to limit its risk associated with the power generation facility once
the construction phase has been completed.
AEP, is the construction agent for Katco, and is responsible for completing
construction by December 31, 2003, subject to unforeseen events beyond AEP's
control.
In the event the project is terminated before completion of construction, AEP
has the option to either purchase the facility for 100% of project costs or
terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation
date of the facility and continues until November 2006. The lease contains
extension options subject to the approval of Katco, and if all extension options
were exercised, the total term of the lease would be 30 years. AEP's lease
payments to Katco are sufficient for Katco to make required debt payments and
provide a return to the investors of Katco. At the end of each lease term, AEP
may renew the lease at fair market value subject to Katco's approval, purchase
the facility at its original construction cost, or sell the facility, on behalf
of Katco, to an independent third party. If the facility is sold and the
proceeds from the sale are insufficient to repay Katco, AEP may be required to
make a payment to Katco for the difference between the proceeds from the sale
and the obligations of Katco, up to 82% of the project's cost. AEP has
guaranteed a portion of the obligations of its subsidiaries to Katco during the
construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360
million, and total costs for the completed facility are expected to be
approximately $510 million. For the 30-year extended lease term, the lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently
as market interest rates increase, the payments under this operating lease will
also increase. Annual payments of approximately $12 million represent future
minimum payments during the initial term calculated using the indexed LIBOR rate
(1.38% at December 31, 2002). The Power Generation Facility collateralizes the
debt obligation of Katco. AEP's maximum exposure to loss as a result of its
involvement with Katco is 100% during the construction phase and up to 82% once
the construction is completed. Maximum loss is deemed to be remote due to the
collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter
of 2003, as a result of the issuance of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP
would record the assets, liabilities, depreciation expense, minority interest
and debt interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.
The lease payments and the guarantee of construction commitments are included in
the Other Commercial Commitments table below.
Minority Interest in Finance Subsidiary
In August 2001 AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne)
and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated
subsidiary of AEP that was capitalized with the assets of Houston Pipe Line
Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million
of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary
and parent of SubOne) preferred stock, that is convertible into AEP common stock
at market price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an unconditional
obligation to fund $83 million from SubOne and $750 million from Steelhead
Investors LLC ("Steelhead" - non-controlling preferred member interest). As
managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and has a capital structure of $750 million of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to
limit its risk associated with Houston Pipe Line Company and Louisiana
Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead receives a
quarterly preferred return equal to an adjusted floating reference rate (4.784%
and 4.413% for the quarters ended December 31, 2002 and 2001, respectively).
Caddis has the right to redeem Steelhead's interest at any time.
The $750 million invested in Caddis by Steelhead was loaned to SubOne. This
intercompany loan to SubOne is due August 2006, and is supported by the natural
gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4
million of preferred stock in AEP Gas Holding. The preferred stock is
convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if SubOne were to reduce its loan with Caddis by $225 million. The credit
agreement between Caddis and SubOne contains covenants that restrict certain
incremental liens and indebtedness, asset sales, investments, acquisitions, and
distributions. The credit agreement also contains covenants that impose minimum
financial ratios. Non-performance of these covenants may result in an event of
default under the credit agreement. Through December 31, 2002, we have complied
with the covenants contained in the credit agreement. In addition, a default
under any other agreement or instrument relating to AEP and certain
subsidiaries' debt outstanding in excess of $50 million is an event of default
under the credit agreement.
The initial period of Steelhead's investment in Caddis is through August 2006.
At the end of the initial period, Caddis will either reset Steelhead's return
rate, re-market Steelhead's interests to new investors, redeem Steelhead's
interests, in whole or in part including accrued return, or liquidate Caddis in
accordance with the provisions of applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events including a default in the payment of the preferred
return, Steelhead's rights include: forcing a liquidation of Caddis and acting
as the liquidator, and requiring the conversion of the AEP Gas Holding preferred
stock into AEP common stock. If Steelhead exercised its rights to force Caddis
to liquidate under these conditions, then AEP would evaluate whether to
refinance at that time or relinquish the assets that support the intercompany
loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are separate and
legally distinct from AEP. The results of operations, cash flows and financial
position of Caddis and SubOne are consolidated with AEP for financial reporting
purposes. Steelhead's investment in Caddis and payments made to Steelhead from
Caddis are currently reported on AEP's income statement and balance sheet as
Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with Steelhead is
$321.4 million of preferred stock, $83 million under the subscription agreement
to Caddis for any losses incurred by Caddis and the cash reserve fund balance of
$34 million (as of December 31, 2002) due Caddis for default under the
intercompany loan agreement. AEP can reduce its maximum exposure related to the
preferred stock by a reduction of $225 million of the intercompany loan.
As of December 31, 2002, we are continuing to review the application of FIN
46 as it relates to the Steelhead transaction.
AEP Credit
AEP Credit entered into a sale of receivables agreement with a group of banks
and commercial paper conduits. Under the sale of receivables agreement, which
expires May 28, 2003, AEP Credit sells an interest in the receivables it
acquires to the commercial 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 and
allowing AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities in
accordance with GAAP. We continue to service the receivables. This off-balance
sheet transaction was entered into to allow AEP credit to repay its outstanding
debt obligations, continue to purchase the AEP operating companies' receivables,
and accelerate its cash collections.
At December 31, 2002, the sale of receivables agreement provided the banks and
commercial paper conduits would purchase a maximum of $600 million of
receivables from AEP Credit, of which $454 million was outstanding. As
collections from receivables sold occur and are remitted, the outstanding
balance for sold receivables is reduced and as new receivables are sold, the
outstanding balance of sold receivables increases. All of the receivables sold
represented affiliate receivables. The commitment's new term under the sale of
receivables agreement will remain at $600 million until May 28, 2003. 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 receivables less an allowance for anticipated uncollectible
accounts.
See Note 23 "Lines of Credit and Sale of Receivables" for further disclosure.
Gavin Plant's flue gas desulfurization system (Gavin Scrubber)
OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated
unconsolidated special purpose entity. JMG has a capital structure of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from pollution control bonds and other bonds. JMG owns the
Gavin Scrubber and leases it to OPCo. The lease is accounted for as an
operating lease with the payment obligations included in the lease footnote.
Payments under the operating lease are based on JMG's cost of financing (both
debt and equity) and include an amortization component plus the cost of
administration. Neither OPCo nor AEP has an ownership interest in JMG and does
not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial
15-year lease term is non-cancelable. At the end of the initial term, OPCo can
renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or
sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition
cost, OPCo must pay the difference to JMG.
The use of JMG allows AEP to enter into an operating lease while keeping the tax
benefits otherwise associated with a capital lease. As of December 31, 2002,
unless the structure of this arrangement is changed, it is reasonably possible
that AEP will consolidate JMG in the third quarter of 2003 as a result of the
issuance of FIN 46. Upon consolidation, AEP would record the assets,
liabilities, depreciation expense, minority interest and debt interest expense
of JMG. AEP would eliminate operating lease expense. AEP's maximum exposure to
loss as a result of its involvement with JMG is approximately $560 million of
outstanding debt and equity of JMG as of December 31, 2002.
Rockport Plant Unit 2
AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.
Summary Obligations Information
The contractual obligations of AEP include amounts reported on the Consolidated
Balance Sheets and other obligations disclosed in the footnotes. The following
table summarizes AEP's contractual cash obligations at December 31, 2002:
Payments Due by Period
(in millions)
Contractual Cash Obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total
---------------------------- ---------------- --------- --------- ------------- -------
Long-term Debt $1,633 $1,817 $2,316 $ 4,354 $10,120
Short-term Debt 3,164 - - - 3,164
Equity Unit Senior Notes - - 376 - 376
Trust Preferred Securities - - - 321 321
Minority Interest In Finance
Subsidiary (a) - - 759 - 759
Preferred Stock Subject to
Mandatory Redemption - - - 84 84
Capital Lease Obligations 70 90 50 18 228
Unconditional Purchase
Obligations (b) 1,405 1,810 989 1,513 5,717
Noncancellable Operating Leases 305 523 479 2,462 3,769
------ ------ ------ ------- -------
Total Contractual
Cash Obligations $6,577 $4,240 $4,969 $ 8,752 $24,538
====== ====== ====== ======= =======
(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.
The SPE's, described under "Off-Balance Sheet Arrangements" above, have been
employed for some of the contractual cash obligations reported in the above
table. The lease of Rockport Plant Unit 2 and the Gavin Scrubbers, the permanent
financing of HPL, and the sale of accounts receivable all use SPE's. Neither AEP
nor any AEP related parties have an ownership interest in the SPE. AEP does not
guarantee the debt of these entities. These SPEs are not consolidated in AEP's
financial statements in accordance with GAAP. As a result, neither the assets
nor the debt of the SPE are included on the Consolidated Balance Sheets. The
future cash obligations payable to the SPEs are included in the above table.
In addition to the amounts disclosed in the contractual cash obligations table
above, AEP and our subsidiaries make commitments in the normal course of
business. These commitments include standby letters of credit, guarantees for
the payment of obligation performance bonds, and other commitments. AEP's
commitments outstanding at December 31, 2002 under these agreements are
summarized in the table below:
Amount of Commitment Expiration Per Period
(in millions)
Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total
---------------------------- ---------------- --------- --------- ------------- -----
Standby Letters of Credit (a) $ 125 $ 1 $ - $ 40 $ 166
Guarantees of the Performance of Outside
Parties (b) 13 17 325 137 492
Guarantees of our Performance 1,159 2 82 9 1,252
Construction of Generating and
Transmission Facilities for
Third Parties (c) 671 83 47 67 868
Other Commercial
Commitments (d) 14 53 11 - 78
------ ---- ---- ---- ------
Total Commercial Commitments $1,982 $156 $465 $253 $2,856
====== ==== ==== ==== ======
(a) AEP has standby letters of credit to third parties. These letters of credit
cover gas and electricity trading contracts, various construction contracts and
credit enhancement for issued bonds. All of these letters of credit were issued
at a subsidiary level of AEP in the subsidiaries' ordinary course of business.
The maximum future payments of these letters of credit are $166 million with
maturities ranging from January 2003 to December 2007. There is no liability
recorded for these letters of credit in accordance with FIN 45. Since AEP is the
parent to all these subsidiaries, it holds all assets of the subsidiary as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.
(b) These amounts are the balances drawn, not the maximum guarantee disclosed in
Note 10.
(c) As construction agent for third party owners of power plants and
transmission facilities, 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 required by contract terms.
(d) Represents estimated future payments for power to be generated at facilities
under construction.
With the exceptions of SWEPCo's guarantee of an unaffiliated mine operator's
obligations (payable upon their default) of $148 million at December 31, 2002,
and OPCo's obligations under a power purchase agreement of $14 million each year
in 2003 through 2005, the obligations in the above table are commitments of AEP
and its non-registrant subsidiaries.
OPCo has entered into a 30-year power purchase agreement for electricity
produced by an unaffiliated entity's three-unit natural gas fired plant. The
plant was completed in 2002 and the agreement will terminate in 2032. Under the
terms of the agreement, OPCo has the option to run the plant until December 31,
2005 taking 100% of the power generated and making monthly capacity payments.
The capacity payments are fixed through December 2005 at $1.2 million per month.
For the remainder of the 30 year contract term, OPCo will pay the variable costs
to generate the electricity it purchases which could be up to 20% of the plant's
capacity. The estimated fixed payments are included in the Other Commercial
Commitments table shown above.
Expenditures for domestic electric utility construction are estimated to be $4
billion for the next three years. Approximately 90% of those construction
expenditures are expected to be financed by internally generated funds.
APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Certificates have been issued by both the WVPSC and the Virginia
SCC authorizing construction and operation of the line. On December 31, 2002,
the United States Forest Service issued a final environmental impact statement
and record of decision to allow the use of federal lands in the Jefferson
National Forest for construction of a portion of the line. We expect additional
state and federal permits to be issued in the first half of 2003. Through
December 31, 2002 we had invested approximately $51 million in this effort. The
line is estimated to cost $287 million including amounts spent to date with
completion in 2006. If the required permits are not obtained and the line is not
constructed, the $51 million investment would be written off adversely affecting
future results of operations and cash flows.
Pension Plans
The Company maintains qualified defined benefit pension plans (Qualified Plans),
which cover substantially all non-union and certain union associates and
unfunded excess plans to provide benefits in excess of amounts permitted to be
paid under the provisions of the tax law to participants in the Qualified Plans.
Additionally, the Company has entered into individual retirement agreements with
certain current and retired executives that provide additional retirement
benefits.
Our pension income for all pension plans approximated $69 million and $44
million for the years ended December 31, 2001 and December 31, 2002,
respectively, and is calculated based upon a number of actuarial assumptions,
including an expected long-term rate of return on our Qualified Plans' assets of
9%. In developing our expected long-term rate of return assumption, we evaluated
input from our actuaries and investment consultants, including their reviews of
asset class return expectations as well as long-term inflation assumptions.
Projected returns by such actuaries and consultants are based on broad equity
and bond indices. We also considered historical returns of the investment
markets as well as our 10-year average return (for the period ended 2002) of
8.8%. We anticipate that our investment managers will continue to generate
long-term returns of at least 9.0%. Our expected long-term rate of return on the
Qualified Plans' assets is based on an asset allocation assumption of 70% with
equity managers, with an expected long-term rate of return of 10.5%, and 28%
with fixed income managers, with an expected long-term rate of return of 6%, and
2% in cash and short term investments with an expected rate of return of 3%.
Because of market fluctuation, our actual asset allocation as of December 31,
2002 was 67% with equity managers and 32% with fixed income managers and 1% in
cash. We believe, however, that our long-term asset allocation on average will
approximate 70% with equity managers, 28% with fixed income managers and the
remaining 2% in cash. We regularly review our actual asset allocation and
periodically rebalance our investments to our targeted allocation when
considered appropriate. We continue to believe that 9.0% is a reasonable
long-term rate of return on our Qualified Plans' assets, despite the recent
market downturn in which our Qualified Plans' assets had a loss of 11.2% for the
twelve months ended December 31, 2002. We will continue to evaluate our
actuarial assumptions, including our expected rate of return, at least annually,
and will adjust as necessary.
We base our determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded. As of December 31, 2002 we had cumulative
losses of approximately $879 million which remain to be recognized in the
calculation of the market-related value of assets. These unrecognized net
actuarial losses result in increases in our future pension costs depending on
several factors, including whether such losses at each measurement date exceed
the corridor in accordance with SFAS No. 87, "Employers' Accounting for
Pensions."
The discount rate that we utilize for determining future pension obligations is
based on a review of long-term bonds that receive one of the two highest ratings
given by a recognized rating agency. The discount rate determined on this basis
has decreased from 7.25% at December 31, 2001 to 6.75% at December 31, 2002. Due
to the effect of the unrecognized actuarial losses and based on an expected rate
of return on our Qualified Plans' assets of 9.0%, a discount rate of 6.75% and
various other assumptions, we estimate that our pension expense for all pension
plans will approximate $2 million, $46 million and $97 million in 2003, 2004 and
2005, respectively. Future actual pension expense will depend on future
investment performance, changes in future discount rates and various other
factors related to the populations participating in our pension plans.
Lowering the expected long-term rate of return on our Qualified Plans, assets by
..5% (from 9.0% to 8.5%) would have reduced our pension income for 2002 by
approximately $19 million. Lowering the discount rate by 0.5% would have reduced
our pension income for 2002 by approximately $8 million.
The value of our Qualified Plans' assets has decreased from $3.438 billion at
December 31, 2001 to $2.795 billion at December 31, 2002. The Qualified Plans
paid out $272 million in benefits to plan participants during 2002 (nonqualified
plans paid out $6 million in benefits). The investment returns and declining
discount rates have changed the status of our Qualified Plans from overfunded
(plan assets in excess of projected benefit obligations) by $146 million at
December 31, 2001 to an underfunded position (plan assets are less than
projected benefit obligations) of $788 million at December 31, 2002. Due to the
Qualified Plans currently being underfunded, the Company recorded a charge to
Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax
Asset of $315 million, offset by a Minimum Pension Liability of $662 million and
a reduction to prepaid costs and intangible assets of $238 million. The charge
to OCI does not affect earnings or cash flow. AEP is in full compliance with all
regulations governing such plans including all Employee Retirement Income
Security Act of 1974 laws. Because of the recent reductions in the funded status
of our Qualified Plans, we expect to make cash contributions to our Qualified
Plans of approximately $66 million in 2003 increasing to approximately $108
million per year by 2005.
Critical Accounting Policies
In the ordinary course of business, AEP has made a number of estimates and
assumptions relating to the reporting of results of operations and financial
condition in the preparation of its consolidated financial statements in
conformity with accounting principles generally accepted in the United States of
America. Actual results could differ significantly from those estimates under
different assumptions and conditions. AEP believes that the following discussion
addresses the most critical accounting policies, which are those that are most
important to the portrayal of the financial condition and results and require
management's most difficult, subjective and complex judgments, often as a result
of the need to make estimates about the effect of matters that are inherently
uncertain.
Revenue Recognition
Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo,
TCC, TNC and SWEPCo) reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide for refunds to customers
that have not yet been made.
When regulatory assets are probable of recovery through regulated rates, we
record them as assets on the balance sheet. We test for probability of recovery
whenever new events occur, for example, issuance of 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 earnings. 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 - Revenues are recognized
on the accrual or settlement basis for normal retail and wholesale electricity
supply sales and electricity transmission and distribution delivery services.
The revenues are recognized in our Consolidated Statements of Operations when
the energy is delivered to the customer and include unbilled as well as billed
amounts. In general, expenses are recorded when purchased electricity is
received and when expenses are incurred.
Domestic Gas Pipeline and Storage Activities - Revenues are recognized from
domestic gas pipeline and storage services when gas is delivered to contractual
meter points or when services are provided. Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts, excluding
wellhead purchases of natural gas, swaps and options for the domestic pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair value during the period are recognized currently in the consolidated
results of operations, appropriately discounted and net of applicable credit and
liquidity reserves.
Energy Marketing and Trading Activities -In 2000, 2001 and throughout the
majority of 2002, AEP engaged in broad non-regulated wholesale electricity,
natural gas and other commodity marketing and trading transactions (trading
activities). AEP's trading activities involved the purchase and sale of energy
under forward contracts at fixed and variable prices and the buying and selling
of financial energy contracts which include exchange traded futures and options
and over-the-counter options and swaps. We used the mark-to-market method of
accounting for trading activities as required by EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains
and losses from settlements of forward trading contracts are recorded net in
revenues. For energy contracts not yet settled, whether physical or financial,
changes in fair value are recorded net as revenues. Such fair value changes are
referred to as unrealized gains and losses from mark-to-market valuations. When
positions are settled and gains and losses are realized, the previously recorded
unrealized gains and losses from mark-to-market valuations are reversed.
Unrealized mark-to-market gains and losses are included in the Consolidated
Balance Sheets as "Energy Trading and Derivative Contracts." In October 2002,
management announced plans to focus on wholesale markets where we own assets.
The majority of trading activities represent physical forward contracts that are
typically settled by entering into offsetting contracts. An example of our
energy trading activities is when, in January, we enter into a forward sales
contract to deliver energy 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 a gain or loss in cash and reverse to
revenues the previously recorded cumulative 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 for a sales contract and the realized cost
for a purchase contract are included on a net basis in revenues with the prior
change in unrealized fair value reversed out of 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 energy
in July. If we do nothing else with these contracts until settlement in July and
if the commodity type, volumes, delivery point, schedule and other key terms
match, then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July.
Mark-to-market accounting for these contracts from this point forward will have
no further impact on operating results but has an offsetting and equal effect on
trading contract assets and liabilities. If the sale and purchase contracts do
not match exactly as to commodity type, volumes, delivery point, schedule and
other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using MTM accounting.
For AEP, the trading of energy options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in revenues until the contracts settle. When these contracts
settle, we record the net proceeds in revenues and reverse the prior cumulative
unrealized net gain or loss.
The fair values of open short-term trading contracts are based on exchange
prices and broker quotes. We mark-to-market open long-term trading contracts
based primarily on valuation models that estimate future energy prices based on
existing market and broker quotes and supply and demand market data and
assumptions. The fair values determined are reduced by the appropriate valuation
adjustments for items such as discounting, liquidity and credit quality. Credit
risk is the risk that the counterparty to the contract will fail to perform or
fail to pay amounts due to AEP. Liquidity risk represents the risk that
imperfections in the market will cause the price to be less than or more than
what the price should be based purely on supply and demand. There are inherent
risks related to the underlying assumptions in models used to fair value open
long-term trading contracts. We have independent controls to evaluate the
reasonableness of our valuation models. However, energy markets, especially
electricity markets, are imperfect and volatile. Unforeseen events can and will
cause reasonable price curves to differ from actual prices throughout a
contract's term and at the time contracts settle. Therefore, there could be
significant adverse or favorable effects on future results of operations and
cash flows if market prices are not consistent with AEP's approach at estimating
current market consensus for forward prices in the current period. This is
particularly true for long-term contracts.
AEP applies MTM accounting to derivatives that are not trading contracts in
accordance with generally accepted accounting principles. Derivatives are
contracts whose value is derived from the market value of an underlying
commodity.
Volatility in energy commodity markets affects the fair values of all of our
open trading and derivative contracts exposing us to market risk and causing our
results of operations to be subject to volatility. See Note 17, "Risk
Management, Financial Instruments and Derivatives" for a discussion of the
policies and procedures used to manage our exposure to market and other risks
from trading activities.
Given the previously discussed reduction in AEP's trading activities, the impact
of mark-to-market accounting on our financial statements is expected to decline
in future periods.
Long-Lived Assets
Long-lived assets, including fixed assets and intangibles, are evaluated
periodically for impairment whenever events or changes in circumstances indicate
that the carrying amount of any such assets may not be recoverable. If the sum
of the undiscounted cash flows is less than the carrying value, we recognize an
impairment loss, measured as the amount by which the carrying value exceeds the
fair value of the asset. The estimate of cash flow is based upon, among other
things, certain assumptions about expected future operating performance. Our
estimates of undiscounted cash flow may differ from actual cash flow due to,
among other things, technological changes, economic conditions, changes to our
business model or changes in our operating performance.
Pension Benefits
We sponsor pension and other retirement plans in various forms covering
substantially all employees who meet eligibility requirements. Several
statistical and other factors which attempt to anticipate future events are used
in calculating the expense and liability related to the plans. These factors
include assumptions about the discount rate, expected return on plan assets and
rate of future compensation increases as determined by management, within
certain guidelines. In addition, our actuarial consultants also use subjective
factors such as withdrawal and mortality rates to estimate these factors. The
actuarial assumptions used may differ materially from actual results due to
changing market and economic conditions, higher or lower withdrawal rates or
longer or shorter life spans of participants. These differences may result in a
significant impact to the amount of pension expense recorded.
New Accounting Pronouncements
See Note 1 to the consolidated financial statements for a discussion of
significant accounting policies and new accounting pronouncements.
Market Risks
As a major power producer and marketer of wholesale electricity and natural gas,
we have certain market risks inherent in our business activities. These risks
include commodity price risk, interest rate risk, foreign exchange risk and
credit risk. They represent the risk of loss that may impact us due to changes
in the underlying market prices or rates.
Policies and procedures have been 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 Executive Committee and
administered by a Chief Risk Officer. The Risk Executive 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. of 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 in the trading portfolio. 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, 2002 a near term typical
change in commodity prices is not expected to have a material effect on our
consolidated 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,
2002 2001
High Average Low High Average Low
(in millions)
AEP $24 $12 $4 $28 $14 $5
After the October announcement of our strategy to reduce trading activity, the
related VaRs were substantially reduced. The average AEP trading VaR for the
fourth quarter 2002 was $7 million as compared to $13 million for fourth quarter
2001. In 2003 we will continue to adjust our VaR limit structure commensurate
with our anticipated level of trading activity.
We also utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $527 million at
December 31, 2002 and $673 million at December 31, 2001. However, since we would
not expect to liquidate our entire debt portfolio in a one year holding period,
a near term change in interest rates should not materially affect consolidated
results of operations or financial position.
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 Michigan
and West Virginia or capped in Indiana. To the extent the fuel supply of the
generating units in these states is not under fixed price long-term contracts,
AEP is subject to market price risk. AEP continues to be protected against
market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana,
Kentucky, Virginia and the SPP area of Texas.
We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree other commodities and as a result we are
subject to price risk. The amount of risk taken by the traders is controlled by
the management of the trading operations and the Company's Chief Risk Officer
and his staff. When the risk from trading activities exceeds certain
pre-determined limits, the positions are modified or hedged to reduce the risk
to be within the limits unless specifically approved by the Risk Executive
Committee.
We employ fair value hedges, cash flow hedges and swaps to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on certain power
trading transactions denominated in foreign currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate
fluctuations in debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.
Credit Risk
AEP limits credit risk by extending unsecured credit to entities based on
internal ratings. In addition, AEP uses Moody's Investors 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 counterparties depending upon
credit quality 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 exposure with any one counterparty is not material to our
financial condition at December 31, 2002. At December 31, 2002 approximately
7% of our exposure was below investment grade as expressed in terms of net MTM
assets. Net MTM assets represents the aggregate difference between the forward
market price for the remaining term of the contract and the contractual price
per counterparty. The following table approximates counterparty credit quality
and exposure for AEP based on netting across AEP entities, commodities and
instruments.
Futures,
Forward
and Swap
Counterparty Contracts Options Total
Credit Quality:
December 31, 2002
(in millions)
AAA/Exchanges $ 26 $ 2 $ 28
AA 307 33 340
A 448 26 474
BBB 700 101 801
Below Investment
Grade 107 11 118
--------- ----------- ------
Total $ 1,588 $ 173 $1,761
======= ======== ======
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, 2002 and 2001 were $109
million and $55 million. These margin accounts are restricted and therefore are
not included in Cash and Cash Equivalents on the Consolidated Balance Sheets. 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 in accordance with generally accepted accounting principles and
include the net change in mark-to-market amounts on a net discounted basis in
revenues. The marking-to-market of open trading contracts contributed an
unrealized $180 million to revenues in 2002. The mark-to-market 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 internally developed valuation models. The gross value is present
valued and reduced by appropriate valuation adjustments for counterparty credit
risks and liquidity risk to arrive at fair value. 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 liquid portion of these curves are validated on a regular basis by the
middle-office through the market data. Illiquid portions of the curves are
validated through a review of the underlying market assumptions and variables
for consistency and reasonableness. The end of the month liquidity reserve is
based on the difference in price between the price curve and the bid price if we
have a long position and the price curve and the ask price if we have a short
position. This provides for a more accurate valuation of energy contracts.
The use of these models to fair value open trading contracts has inherent risks
relating to the underlying assumptions employed by such models. Independent
controls are in place to evaluate the reasonableness of the price curve models.
Significant adverse or favorable effects on future results of operations and
cash flows could occur if market prices, at the time of settlement, do not
correlate with the Company developed price models.
The effect on the Consolidated Statements of Operations of marking to market
open electricity trading contracts in the Company's regulated jurisdictions, is
deferred as regulatory assets (losses) or liabilities (gains) since these
transactions are included in cost of service on a settlement basis for
ratemaking purposes. Unrealized mark-to-market gains and losses from trading 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).
December 31,
2002 2001 2000
---- ---- ----
(in millions)
Revenues
(including
mark- to-
market
adjustment) $14,555 $12,767 $11,113
Fuel and
Purchased
Energy
Expense 6,307 4,944 3,880
------- ------- -------
Net Revenues $ 8,248 $ 7,823 $ 7,233
======= ======= =======
Mark-to-Market
Revenues $180 $207 $187
=== ==== ====
Percentage of
Net Revenues
Represented by
Mark-to-Market
On Open
Trading Positions
2% 3% 3%
== == ==
The following tables analyze the changes in fair values of trading assets and
liabilities. The first table "Net Fair Value of Mark-to-Market Energy Trading
and Derivative Contracts" shows how the net fair value of energy trading
contracts was derived from the amounts included in the Consolidated Balance
Sheets line item "Energy Trading and Derivative Contracts." The next table
"Mark-to-Market Energy Trading and Derivative Contracts" disaggregates realized
and unrealized changes in fair value; identifies changes in fair value as a
result of changes in valuation methodologies; and reconciles the net fair value
of energy trading contracts and related derivatives at December 31, 2001 of $448
million to December 31, 2002 of $250 million. Contracts realized/settled during
the period include both sales and purchase contracts. The third table
"Mark-to-Market Energy Trading and Derivative Contract Maturities" shows
exposures to changes in fair values and realization periods over time for each
method used to determine fair value.
Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts
December 31
----------------------
2002 2001
---- ----
(in millions)
Energy Trading and Derivative Contracts:
Current Asset $1,046 $ 2,125
Long-term Asset 824 795
Current Liability (1,147) (1,877)
Long-term Liability (484) (603)
------- ------
Net Fair Value of Energy Trading and Derivative Contracts 239 440
Non-trading related derivative liabilities 11* -
Assets held for sale (CitiPower) - 8
------ -------
Net Fair Value of Energy Trading and Derivative Contracts $ 250 $ 448
====== =======
* Excludes $6 million Loss recorded in an equity investment.
The above net fair value of energy trading and derivative contracts includes
$180 million at December 31, 2002, in unrealized mark-to-market gains that are
recognized in the Consolidated Statements of Operations at December 31, 2002.
Mark-to-Market Energy Trading and Derivative Contracts
Total
(in millions)
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2001 $ 448
(Gain) Loss from Contracts Realized/Settled During the Period (182) (a)
Fair Value of New Open Contracts When Entered Into During the Period
68 (b)
Net Option Premiums Paid/(Received) (130) (c)
Change in fair value due to Methodology Changes 1 (d)
Change in Market Value of Energy Trading Contracts
Allocated to Regulated Jurisdictions (2) (e)
Changes in Market Value of Contracts 47 (f)
-----
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2002 $ 250
=====
(a) "(Gain) Loss from Contracts Realized/Settled During the Period" include
realized gains from energy trading contracts and related derivatives that
settled during 2002 that were entered into prior to 2002.
(b) The "Fair Value of New Open Contracts When Entered Into During Period"
represents the fair value of long-term contracts entered into with
customers during 2002. The fair value is calculated as of the execution
of the contract. Most of the fair value comes from longer term fixed
price contracts with customers that seek to limit their risk against
fluctuating energy prices. The contract prices are valued against market
curves representative of the delivery location.
(c) "Net Option Premiums Paid/(Received)" reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option
contracts that were entered into in 2002.
(d) The Company changed the discount rate applied to its trading portfolio
from BBB+ Utility to LIBOR in the second quarter which increased fair
value by $10 million. In addition, the Company changed its methodology
in valuing a spread option model so as to more accurately reflect the
exercising of power transactions at optimal prices which reduced fair
value by $9 million.
(e) "Change in Market Value of Energy Trading Contracts Allocated to
Regulated Jurisdictions" relates to the net gains of those contracts that
are not reflected in the Consolidated Statements of Operations. These
net gains are recorded as regulatory liabilities for those subsidiaries
that operate in regulated jurisdictions.
(f) "Changes in Market Value of Contracts" represents the fair value change in
the trading portfolio due to market fluctuations during the current
period. Market fluctuations are attributable to various factors such as
supply/demand, weather, storage, etc.
Mark-to-Market Energy Trading and Derivative Contract Maturities
Fair Value of Contracts at December 31, 2002
Maturities
(in millions)
AEP Consolidated Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
-------------------- ------ --------- --------- ---------- -----
Prices Actively Quoted (a) $(32) $ 69 $ - $ - $ 37
Prices Provided by Other External
Sources (b) 24 189 11 - 224
Prices Based on Models and Other
Valuation Methods (c) (84) 13 36 24 (11)
---- ---- --- --- ------
Total $(92) $271 $47 $24 $ 250
==== ==== === === =====
(a) "Prices Actively Quoted" represents the Company's exchange traded
futures, options and euro dollar positions.
(b) "Prices Provided by Other External Sources" represents the Company's
positions in natural gas, power, and coal at points where
over-the-counter broker quotes are available. Some prices from
external sources are quoted as strips (one bid/ask for Nov-Mar,
Apr-Oct, etc). Such transactions have also been included in this
category.
(c) "Prices Based on Models and Other Valuation Methods" contain the
following: the value of the Company's adjustments for liquidity and
counterparty credit exposure, the value of contracts not quoted by an
exchange or an over-the-counter broker, the value of transactions for
which an internally developed price curve was developed as a result of
the long dated nature of certain transactions, and the value of
certain structured
transactions.
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
17, "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, operating and maintaining utility plant
assets. 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
Four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which our domestic electric utility companies operate have
implemented retail restructuring legislation. Three other states (Arkansas,
Oklahoma and West Virginia) initially adopted retail restructuring legislation,
but have since either delayed the implementation of that legislation, or
repealed the legislation (Arkansas). In general, retail restructuring
legislation provides for a transition from cost-based rate 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 have discontinued the application of SFAS 71, regulatory
accounting for the generation business. AEP has not discontinued its regulatory
accounting for its subsidiaries doing business in Michigan and Oklahoma.
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
our state regulatory jurisdictions affected by restructuring legislation is
presented in Note 8 of the Notes to Consolidated Financial Statements.
Corporate Separation
We have filed with the FERC and SEC seeking approval to separate our regulated
and unregulated operations. Our plan for corporate separation would have
complied with the requirements of Texas and Ohio restructuring legislation. In
Texas, we intended to transfer the generation assets from the integrated
electric operating companies (CPL and WTU) which operated in ERCOT prior to the
effective date of the Texas Restructuring Legislation to unregulated generation
companies. In Ohio, we intended to transfer transmission and distribution assets
from the integrated companies to two new wires companies leaving CSPCo and OPCo
as generating companies. We proposed amendments to the power pooling agreements
to remove the four Ohio and Texas generating companies. Only those operating
companies that continue to exist as integrated utilities would have been
included in the amended power pooling agreements, which would govern energy
exchanges among members and the allocation of their off-system purchases and
sales. In connection with corporate separation, certain new interim power supply
agreements have been proposed to provide power to distribution companies who
will no longer own generation assets. Several state commissions, wholesale
customer groups and other interested parties intervened in the FERC proceeding.
Negotiated settlement agreements with the state regulatory commissions and other
major intervenors were filed with the FERC in December 2001. In September 2002,
the FERC conditionally approved our corporate separation plan as modified by the
settlement agreements. Terms in the settlement agreements would be effective
upon implementation of corporate separation. In addition, SEC approval of our
corporate separation plan is required for its implementation. The Arkansas
Commission intervened with the SEC, which has extended the length of time needed
for the SEC's review. In order to execute this separation, we may be required to
retire various debt securities and transfer assets between legal entities.
With the changes in our business strategy in response to current energy
market/business conditions, management is evaluating changes to our corporate
separation plans, including determining whether legal corporate separation is
appropriate.
RTO Formation
FERC Order No. 2000 and many of the settlement agreements with the FERC and
state regulatory commissions to approve the AEP-CSW merger, required the
transfer of functional control of our transmission system to RTOs.
AEP East companies initially participated in the formation of the Alliance RTO.
In December 2001, the FERC reversed prior approvals and rejected the Alliance
RTO's filing. Subsequently, in May 2002 AEP announced an agreement with the PJM
Interconnection to pursue terms for AEP East companies to participate in PJM
with final agreements to be negotiated. In July 2002, the FERC conditionally
approved our decision for AEP East companies to join PJM subject to certain
conditions being met. The performance of these conditions are only partially
under our control. In December 2002, AEP East companies in Indiana, Kentucky,
Ohio and Virginia filed for state regulatory commission approval of their plans
to transfer functional control of their transmission system to PJM based on
statutory or regulatory requirements in those states. Those proceedings are
currently pending. In February 2003, the Virginia legislature enacted
legislation that would prohibit the transfer to an RTO, until at least July
2004, which is currently awaiting signature by the Governor of Virginia.
AEP West companies are members of ERCOT or the SPP. In May 2002, FERC accepted,
conditionally, filings related to a proposed consolidation of the MISO and the
SPP. In that order the FERC required the AEP West companies in SPP to file
reasons why they should not be required to join MISO. In August 2002, we
notified the FERC of our intent that our transmission assets in SPP would
participate in MISO. Our SPP companies are also regulated by state public
utility commissions, and the Louisiana and Arkansas commissions also filed
responses to the FERC's RTO order indicating that additional analysis was
required. Regulatory activities concerning various RTO issues are ongoing in
Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory
actions and proceedings or their impact on the timing and operation of RTOs, our
transmission operations or future results of operations and cash flows.
FERC Proposed Standard Market Design Security Standards
In 2002, the FERC issued its Standard Market Design (SMD) notice of proposed
rulemaking seeking to standardize the structure and operation of wholesale
electricity markets across the country. The FERC published for comment its
proposed security standards as part of the SMD. These standards are intended to
ensure all market participants have a basic security program that effectively
protects the electric grid and related market activities. Because the rule is
not yet finalized, management cannot predict the effect of the final rule on our
operations and financial results. See Note 9 for a complete discussion of these
proposals.
Litigation
AEP is involved in various litigation. The details of significant litigation
contingencies are disclosed in Note 9 and summarized below.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corp. and its subsidiaries which are pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's bankruptcy,
AEP had open trading contracts and trading accounts receivables and payables
with Enron and various HPL related contingencies and indemnities including
issues related to the underground Bammel gas storage facility and the cushion
gas (or pad gas) required for its normal operation.
We believe that we have the right to utilize offsetting receivables and payables
and related collateral across various Enron entities by offsetting approximately
$110 million of trading payables owed to various Enron entities against trading
receivables due to us. We believe we have legal defenses to any challenge that
may be made to the utilization of such offsets. At this time we are unable to
predict the ultimate resolution of these issues or their impact on results of
operations and cash flows. See Note 9 for further discussion.
COLI
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 our consolidated federal
income tax returns related to a COLI program resulted in a $319 million
reduction in Net Income for 2000. AEP has appealed the Court's decision. See
Note 18 for further discussion.
Shareholders' Litigation
In 2002 lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against AEP, certain
AEP executives, members of the AEP Board of Directors and certain investment
banking firms. These cases are in the initial pleading stage. AEP intends to
vigorously defend against these actions. See Note 9 for further discussion.
California Lawsuit
In 2002 the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies including AEP and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP intends to
vigorously defend against this action. See Note 9 for further discussion.
FERC Wholesale Fuel Complaints
In May 2000 and November 2001 certain TNC wholesale customers filed complaints
with FERC alleging that TNC had overcharged them through the fuel adjustment
clause for certain purchased power costs. The final resolution of this matter
could have a negative impact on future results of operations, cash flow and
financial condition. See Note 6 for further discussion.
Merger Litigation
In January 2002, a federal court ruled that the SEC did not properly find that
the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and
sent the case back to the SEC for further review. Management believes that the
merger meets the requirements of the PUHCA and expects the matter to be resolved
favorably. See Note 9 for further discussion.
Arbitration of Williams Claim
In 2002 AEP filed its demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
Although management is unable to predict the outcome of this matter, it is not
expected to have a material impact on results of operations, cash flows or
financial condition. See Note 9 for further discussion.
Energy Market Investigations
During 2002 the FERC, the California attorney general, the PUCT, the SEC, the
Department of Justice and the U.S. Commodity Futures Trading Commission (CFTC)
initiated investigations into whether any entity, including Enron, manipulated
short-term prices in electric energy or natural gas markets, exercised undue
influence over wholesale prices or participated in fraudulent trading practices.
We have and will continue to provide information to the FERC, the SEC, state
officials and the CFTC as required. See Note 9 for further discussion.
FERC Market Power Mitigation
A FERC order on our triennial market based wholesale power rate authorization
update required certain mitigation actions that we would need to take for
sales/purchases within our control area and required us to post information on
our website regarding our power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an order
delaying the effective date of the mitigation plan until after a planned
technical conference on market power determination. No such conference has been
held and management is unable to predict the timing of any further action by the
FERC or its affect on future results of operations and cash flows.
Other Litigation
We 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
We will confront several new environmental requirements over the next decade
with the potential for substantial control costs and premature retirement of
some generating plants. These policies include: stringent controls on sulfur
dioxide (SO2), nitrogen oxide (NOx) and mercury (Hg) emissions from future
regulations or laws, or an adverse decision in the New Source Review litigation;
a new Clean Water Act rule to reduce fish killed at once-through cooled power
plants; and a possible future requirement to reduce carbon dioxide (CO2)
emissions as the world endeavors to stabilize atmospheric concentrations of
greenhouse gas emissions and avert global climatic changes.
Our environmental policy requires full compliance with all applicable legal
requirements. In support of this policy, we invest in research through groups
like the Electric Power Research Institute and directly through demonstration
projects for new emission control technologies. We intend to continue in a
leadership role to protect and preserve the environment while providing vital
energy commodities and services to customers at fair prices.
We have a proven record of efficiently producing and delivering electricity and
gas while minimizing the impact on the environment. We have spent billions of
dollars to equip many of our facilities with pollution control technologies.
Multi-pollutant control legislation has been introduced in Congress and is
supported by the Bush Administration. The legislation would regulate NOx, SO2,
Hg and possibly CO2 emissions from electric generating plants. We are an
advocate of comprehensive, multi-pollutant legislation so that compliance
planning can be coordinated and collateral emission reductions maximized.
Optimally, such legislation would establish reasonable emission reduction
targets and compliance timetables based on sound science, utilize nationwide
cap-and-trade programs for achieving compliance as cost-effectively as possible,
protect fuel diversity and preserve the reliability of the nation's electric
supply. Management is unable to predict the timing or magnitude of additional
pollution control laws or regulations. If additional control technology is
required on our facilities and their costs are not recoverable from customers
through regulated rates or market prices, they could adversely affect future
results of operations and cash flows. The following discussions explain existing
control efforts, litigation and other pending matters related to environmental
issues for AEP companies.
Federal EPA Complaint and Notice of Violation
Since 1999 AEP has been involved in litigation regarding generating plant
emissions under the Clean Air Act. Federal EPA, a number of states and special
interest groups alleged that AEP System companies modified certain units at coal
fired generating plants in violation of the Clean Air Act over a 20 year period.
Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense.
Management is unable to estimate the loss or range of loss related to the
contingent liability under the Clear Air Act proceedings and unable to predict
the timing of resolution of these 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 or any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial condition unless
such costs can be recovered. See Note 9 for further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (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. The compliance date for these rules is May 31, 2004.
In 2000, the Texas Commission on Environmental Quality (formerly the Texas
Natural Resource Conservation Commission) adopted rules requiring significant
reductions in NOx emissions from utility sources, including TCC and SWEPCo. The
compliance date is May 2003 for TCC and May 2005 for SWEPCo.
AEP is installing a variety of emission control technologies to reduce NOx
emissions to comply with the applicable state and Federal NOx requirements
including selective catalytic reduction (SCR) technology and non-SCR
technologies. The AEP NOx compliance plan is a dynamic plan that is continually
reviewed and revised. Our current estimates indicate that compliance with the
above rules could result in required capital expenditures in the range of $1.3
billion to $2 billion of which $843 million has been spent through December 31,
2002. 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. See
Note 9 for further discussion.
Superfund and State Remediation
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
authorizes Federal EPA to administer the clean-up programs. As of year-end 2002,
subsidiaries of AEP are named by the Federal EPA as a PRP for five sites. There
are six additional sites for which we have received information requests which
could lead to PRP designation. We have also been named potentially liable at six
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 we
have been named a PRP or defendant, our 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 our 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 superfund liability has been interpreted by the
courts as 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
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 emissions of greenhouse gases, chiefly CO2, 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 in 2003. 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
that 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. AEP has for many years been a leader in pursuing voluntary actions to
control greenhouse gas emissions. We recently expanded on our commitment in this
area by joining the Chicago Climate Exchange, a pilot greenhouse gas emission
reduction and trading program, under which we are obligated to reduce or offset
18 million tons of CO2 emissions during 2003-2006.
The acquisition of 4,000 MW of coal-fired generation in the United Kingdom in
December 2001 exposes these assets to potential CO2 emission control obligations
since the U.K. has become a party to the Kyoto Protocol.
Control of Mercury Emissions
In December 2000 Federal EPA issued a regulatory determination listing the
electric generating sector as a source category under the Clean Air Act for
development of maximum achievable control technology standards to control
emissions of hazardous air pollutants, including Hg. Federal EPA is expected to
issue proposed regulations in 2003 and develop a final rule in 2004. We cannot
predict the outcome of these regulatory proceedings, or the costs to comply with
any new standards adopted by Federal EPA. The costs associated with compliance
could be material. However, 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.
Costs for Spent Nuclear Fuel and Decommissioning
I&M, as the owner of the Cook Plant, and TCC, 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 I&M and TCC participate in the DOE's
SNF disposal program which is described in Note 9 of the Notes to Consolidated
Financial Statements. Since 1983 I&M has collected $303 million from customers
for the disposal of nuclear fuel consumed at the Cook Plant. $117 million of
these funds have been deposited in external trust funds to provide for the
future disposal of SNF and $186 million has been remitted to the DOE. TCC has
collected and remitted to the DOE, $53 million for the future 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 TCC 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 under 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 standard 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. On January 17,
2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of
liability. The case continues on the issue of damages owed to I&M by the DOE. 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
of SNF and the cost of decommissioning will continue to increase.
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 (now Exelon Generation Company, LLC). The settlement adjusted the
fees Exelon was required to pay to DOE for disposal of SNF. The fee adjustment
allowed Exelon to skip payments to the DOE to make up for Exelon's damages from
DOE's breach of its contract obligation to dispose of SNF from commercial
nuclear power plants. The companies believe the settlement was unlawful as it
would force other utilities (rather than DOE) to compensate Exelon for the
damages it had incurred from DOE's breach of contract. In September 2002, the
U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly
by adopting the fee adjustment provision of this settlement, that the fee
adjustment provisions of the settlement harmed other utilities who pay into the
fund and violated the federal nuclear waste management laws and that the fee
adjustment provisions of the settlement were null and void.
The cost to decommission nuclear plants is affected by both NRC regulations and
the delayed 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, 2002, the
total decommissioning trust fund balance for Cook Plant was $618 million which
includes earnings on the trust investments. Studies completed in 1999 for STP
estimate TCC's share of decommissioning cost to be $289 million in 1999
non-discounted dollars. Amounts collected from customers to decommission STP
have been placed in an external trust. At December 31, 2002, the total
decommissioning trust fund for TCC's share of STP was $98 million which includes
earnings on the trust investments. Estimates from the decommissioning studies
could continue to escalate due to the uncertainty in the SNF disposal program
and the length of time that SNF may need to be stored at the plant site. We will
work with regulators and customers to recover the remaining estimated costs of
decommissioning Cook Plant and STP. However, future results of operation, cash
flows and possibly financial conditions would be adversely affected if the cost
of SNF disposal and decommissioning continues to increase and cannot be
recovered.
Other Environmental Concerns
We are exposed to other environmental concerns which are not considered to be
material or potentially material at this time. Should they become significant or
should any new concerns be uncovered that are material, they could have a
material adverse effect on results of operations and possibly financial
condition. AEP performs environmental reviews and audits on a regular basis for
the purpose of identifying, evaluating and addressing environmental concerns and
issues.
Other Matters
Seasonality
Sale of electric power is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change depending on the nature and location
of facilities we acquire and the terms of power sale contracts we enter. In
addition, AEP has historically sold less power, and consequently earned less
income, when weather conditions are milder. AEP expects that unusually mild
weather in the future could diminish its results of operations and may impact
its financial condition.
Sustained Earnings Improvement Initiative
In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth. Termination benefits expense relating to 1,120 terminated
employees totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. We determined that the termination of the employees under our SEI
initiative did not constitute a curtailment under the provisions of SFAS No. 88
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits". In addition, certain buildings and
corporate aircraft are being sold in an effort to reduce ongoing operating
expenses. See Note 11 for additional information.
Non-Core Wholesale Investments
Additional market deterioration associated with our non-core wholesale
investments, including our U.K. operations, could have an adverse impact on our
future results of operations and cash flows. Significant long-term changes in
external market conditions could lead to additional write-offs and potential
divestitures of our wholesale investments, including, but not limited to, our
U.K. operations.
Elk City Referendum
In October 2002, the City Commission of Elk City, Oklahoma voted to hold a
referendum seeking voter approval of a $20.4 million acquisition of PSO's
distribution assets within the city limits. The vote occurred in December 2002
with the referendum being defeated.
Snohomish Settlement
In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract.
Investments Limitations
Our investment in certain types of activities, including guarantees of debt, is
limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling
securities in an amount up to 100% of our average quarterly consolidated
retained earnings balance for investment in EWGs and FUCOs. At December 31,
2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including guarantees
of debt, compared to AEP's limit of $2.8 billion.
SEC rules under PUHCA permit AEP to invest up to 15% of consolidated
capitalization (such amount was $3.2 billion at December 31, 2002) in
energy-related companies, including marketing and/or trading of electricity, gas
and other energy commodities.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
-------------------------------------
(in millions - except per share amounts)
Year Ended December 31,
--------------------------
2002 2001 2000
---- ---- ----
REVENUES:
Wholesale Electricity $ 8,366 $ 6,976 $ 7,392
Wholesale Gas 2,622 2,321 442
Domestic Electricity Delivery 3,551 3,356 3,174
Other Investment 16 114 105
-------- ------- -------
TOTAL REVENUES 14,555 12,767 11,113
-------- ------- -------
EXPENSES:
Fuel and Purchased Energy:
Electricity 3,154 2,195 3,470
Gas 3,153 2,749 410
-------- ------- -------
TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880
Maintenance and Other Operation 4,013 3,710 3,482
Non-recoverable Merger Costs 10 21 203
Asset Impairments 867 - -
Depreciation and Amortization 1,377 1,243 1,091
Taxes Other Than Income Taxes 718 667 683
-------- ------- -------
TOTAL EXPENSES 13,292 10,585 9,339
-------- ------- -------
OPERATING INCOME 1,263 2,182 1,774
OTHER INCOME 445 335 95
LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 - -
LESS: OTHER EXPENSES 321 187 77
LESS: INTEREST 785 844 999
PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIES 11 10 11
MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -
-------- ------- -------
INCOME BEFORE INCOME TAXES 235 1,463 782
INCOME TAXES 214 546 602
-------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS
AND CUMULATIVE EFFECT 21 917 180
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122
EXTRAORDINARY LOSSES (NET OF TAX):
DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - (48) (35)
LOSS ON REACQUIRED DEBT - (2) -
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -
-------- ------- -------
NET INCOME (LOSS) $ (519) $ 971 $ 267
======== ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322
=== === ===
EARNINGS (LOSS) PER SHARE:
Income Before Discontinued Operations, Extraordinary Items and Cumulative
of Accounting Change $ 0.06 $ 2.85 $ 0.56
Discontinued Operations (0.57) 0.26 0.38
Extraordinary Losses - (0.16) (0.11)
Cumulative Effect of Accounting Change (1.06) 0.06 -
------ ------ ------
Earnings (Loss) Per Share (Basic and Diluted) $(1.57) $ 3.01 $ 0.83
====== ====== ======
CASH DIVIDENDS PAID PER SHARE $ 2.40 $2.40 $2.40
====== ===== =====
See Notes to Consolidated Financial Statements
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
---------------------------
(in millions - except share data)
December 31,
2002 2001
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 1,213 $ 224
Accounts Receivable:
Customers 466 343
Miscellaneous 1,394 1,365
Allowance for Uncollectible Accounts (119) (69)
Fuel, Materials and Supplies 1,166 1,037
Energy Trading and Derivative Contracts 1,046 2,125
Other 935 639
------- -------
TOTAL CURRENT ASSETS 6,101 5,664
------- -------
PROPERTY PLANT AND EQUIPMENT:
Electric:
Production 17,031 17,054
Transmission 5,882 5,764
Distribution 9,573 9,309
Other (including gas and coal mining assets
and nuclear fuel) 3,965 4,272
Construction Work in Progress 1,406 1,015
------- -------
Total Property, Plant and Equipment 37,857 37,414
Accumulated Depreciation and Amortization 16,173 15,310
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104
------- -------
REGULATORY ASSETS 2,688 3,162
------- -------
SECURITIZED TRANSITION ASSETS 735 -
------- -------
INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633
------- -------
ASSETS HELD FOR SALE 247 721
------- -------
ASSETS OF DISCONTINUED OPERATIONS - 3,954
------- -------
GOODWILL 396 392
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795
------- -------
OTHER ASSETS 1,783 1,872
------- -------
TOTAL ASSETS $34,741 $39,297
======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
December 31,
2002 2001
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,042 $ 1,914
Short-term Debt 3,164 4,011
Long-term Debt Due Within One Year* 1,633 1,095
Energy Trading and Derivative Contracts 1,147 1,877
Other 1,804 1,924
------- -------
TOTAL CURRENT LIABILITIES 9,790 10,821
------- -------
LONG-TERM DEBT* 8,487 8,410
------- -------
EQUITY UNIT SENIOR NOTES 376 -
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603
------- -------
DEFERRED INCOME TAXES 3,916 4,500
------- -------
DEFERRED INVESTMENT TAX CREDITS 455 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 185 194
------- -------
OTHER NONCURRENT LIABILITIES 1,903 1,334
------- -------
LIABILITIES HELD FOR SALE 91 87
------- -------
LIABILITIES OF DISCONTINUED OPERATIONS - 2,582
------- -------
COMMITMENTS AND CONTINGENCIES (Note 9)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 321 321
------- -------
MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750
------- -------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 145 156
------- -------
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
2002 2001
---- ----
Shares Authorized. .600,000,000 600,000,000
Shares Issued. . . .347,835,212 331,234,997
(8,999,992 shares were held in treasury
at December 31, 2002 and 2001) 2,261 2,153
Paid-in Capital 3,413 2,906
Accumulated Other Comprehensive Income (Loss) (609) (126)
Retained Earnings 1,999 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 7,064 8,229
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $34,741 $39,297
======= =======
*See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(in millions)
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
OPERATING ACTIVITIES:
Net Income (Loss) $ (519) $ 971 $ 267
Plus: Discontinued Operations 540 (86) (122)
------ ------- ------
Net Income from Continuing Operations 21 885 145
Adjustments for Noncash Items:
Asset Impairments, Investment Value and Other Impairments 1,188 - -
Depreciation and Amortization 1,403 1,277 1,152
Deferred Investment Tax Credits (31) (29) (36)
Deferred Income Taxes (66) 157 (190)
Amortization of Operating Expenses and Carrying Charges 40 40 48
Cumulative Effect of Accounting Change - (18) -
Equity Earnings of Yorkshire Electricity Group plc - - (44)
Extraordinary Loss - 50 35
Deferred Costs Under Fuel Clause Mechanisms (31) 340 (449)
Mark-to-Market of Energy Trading Contracts 263 (257) (170)
Miscellaneous Accrued Expenses 30 (384) 217
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (152) 1,766 (1,530)
Fuel, Materials and Supplies (127) (78) 149
Accrued Revenues (283) 35 (71)
Accounts Payable 52 (478) 1,292
Taxes Accrued (216) (147) 171
Payment of Disputed Tax and Interest Related to COLI - - 319
Change in Other Assets (177) (239) (283)
Change in Other Liabilities (237) (161) 386
------ ------- -------
Net Cash Flows From Operating Activities 1,677 2,759 1,141
------- ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (1,722) (1,654) (1,468)
Purchase of Gas Pipe Line - (727) -
Purchase of U.K. Generation - (943) -
Purchase of Coal Company - (101) -
Purchase of Barging Operations - (266) -
Purchase of Wind Generation - (175) -
Proceeds from Sale of Retail Electric Providers 146 - -
Proceeds from Sale of Foreign Investments 1,117 383 -
Proceeds from Sale of U.S. Generation - 265 -
Other 37 (42) (18)
------- ------- -------
Net Cash Flows Used For Investing Activities (422) (3,260) (1,486)
------- ------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock 656 11 14
Issuance of Minority Interest - 744 -
Issuance of Long-term Debt 2,893 2,863 878
Issuance of Equity Unit Senior Notes 334 - -
Retirement of Cumulative Preferred Stock (10) (5) (21)
Retirement of Long-term Debt (2,514) (1,570) (1,303)
Change in Short-term Debt (net) (829) (790) 1,328
Dividends Paid on Common Stock (793) (773) (805)
Dividends on Minority Interest in Subsidiary - (5) -
------- ------- -------
Net Cash Flows From (Used for) Financing Activities (263) 475 91
------- ------- -------
Effect of Exchange Rate Changes on Cash (3) (1) 30
------- ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 989 (27) (224)
Cash and Cash Equivalents from Continuing Operations - Beginning of Period 224 251 475
------- ------- -------
Cash and Cash Equivalents from Continuing Operations - End of Period $1,213 $ 224 $ 251
====== ======= =======
Net Increase (Decrease) in Cash and Cash Equivalents from
Discontinued Operations $ (100) $ 17 $ (17)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 108 91 108
------ ------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 8 $ 108 $ 91
====== ======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income
-------------------------------------------------------------------------------
(in millions)
Accumulated
Other
Common Stock Paid-In Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
DECEMBER 31, 1999 331 $2,149 $2,898 $3,630 $ (4) $8,673
Issuances - 3 11 - - 14
Cash Dividends Declared - - - (805) - (805)
Other - - 6 (2) - 4
------
7,886
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (119) (119)
Reclassification Adjustment
For Loss Included in Net Income - - - - 20 20
Net Income - - - 267 - 267
------
Total Comprehensive Income 168
--- ------ ------ ------ ----- ------
DECEMBER 31, 2000 331 2,152 2,915 3,090 (103) 8,054
Issuances - 1 9 - - 10
Cash Dividends Declared - - - (773) - (773)
Other - - (18) 8 - (10)
------
7,281
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (14) (14)
Unrealized Gain (Loss) on
Hedged Derivatives (3) (3)
Minimum Pension Liability - - - - (6) (6)
Net Income - - - 971 971
------
Total Comprehensive Income 948
--- ------ ------ ------ ----- ------
DECEMBER 31, 2001 331 2,153 2,906 3,296 (126) 8,229
Issuances 17 108 568 - - 676
Cash Dividends Declared - - - (793) - (793)
Other - - (61) 15 - (46)
------
(163)
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - 117 117
Unrealized Gain (Loss) on
Hedged Derivatives (13) (13)
Minimum Pension Liability - - - - (585) (585)
Unrealized Loss on Securities Available
For Sale (2) (2)
Net Income (Loss) - - - (519) (519)
------
Total Comprehensive Income (1,002)
DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064
=== ====== ====== ====== ====== ======
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
2. Extraordinary Items and Cumulative Effect
3. Goodwill and Other Intangible Assets
4. Merger
5. Nuclear Plant Restart
6. Rate Matters
7. Effects of Regulation
8. Customer Choice and Industry Restructuring
9. Commitments and Contingencies
10. Guarantees
11. Sustained Earnings Improvement Initiative
12. Acquisitions, Dispositions and Discontinued Operations
13. Asset Impairments and Investment Value Losses
14. Benefit Plans
15. Stock-Based Compensation
16. Business Segments
17. Risk Management, Financial Instruments and Derivatives
18. Income Taxes
19. Basic and Diluted Earnings Per Share
20. Supplementary Information
21. Power and Distribution Projects
22. Leases
23. Lines of Credit and Sale of Receivables
24. Unaudited Quarterly Financial Information
25. Trust Preferred Securities
26. Minority Interest in Finance Subsidiary
27. Equity Units
1. Significant Accounting Policies:
Business Operations - AEP's (the Company's) principal business conducted by its
eleven domestic electric utility operating companies is the generation,
transmission and distribution of electric power. These companies are subject to
regulation by the FERC under the Federal Power Act and follow the Uniform System
of Accounts prescribed by FERC. They are subject to further regulation with
regard to rates and other matters by state regulatory commissions.
AEP also engages in wholesale marketing and trading of electricity, natural gas
and to a lesser extent, other commodities in the United States and Europe. In
addition, the Company's domestic operations include non-regulated independent
power and cogeneration facilities, coal mining and intra-state midstream natural
gas operations in Louisiana and Texas.
International operations include supply of electricity and other non-regulated
power generation projects in the United Kingdom, and to a lesser extent in
Mexico, Australia, China and the Pacific Rim region. These operations are either
wholly-owned or partially-owned by various AEP subsidiaries. We also maintained
operations in Brazil through the fourth quarter of 2002. See Note 13 for
discussion of impaired investments and assets held for sale.
The Company also operates domestic barging operations, provides various energy
related services and furnishes communications related services domestically. See
Note 13 for further discussion of changes in our communications related business
and other business operations announced in 2002.
Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The
rates charged by the domestic utility subsidiaries are approved by the FERC and
the state utility commissions. The FERC regulates wholesale electricity
operations and transmission rates and the state commissions regulate retail
rates. The prices charged by foreign subsidiaries located in China, Mexico and
Brazil are regulated 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. 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.
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 TCC, TNC, and
SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note
8, "Customer Choice and Industry Restructuring" for additional information.
Use of Estimates - The preparation of these financial statements in conformity
with generally accepted accounting principles necessarily includes the use of
estimates and assumptions by management. Actual results could differ from those
estimates.
Property, Plant and Equipment - Domestic electric utility property, plant and
equipment are stated at original cost of the acquirer. Property, plant and
equipment of the non-regulated operations and other investments are stated at
their fair market value at acquisition plus the original cost of property
acquired or constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. For cost-based
rate-regulated operations, retirements from the plant accounts and associated
removal costs, net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overhead incurred to operate and maintain plant
are included in operating expenses. Plants are tested for impairment as required
under SFAS 144. See further discussion of impairments in Note 13.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- AFUDC is a noncash, nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated electric
utility plant. It represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 2002, 2001 and
2000 were not significant. Effective with the discontinuance of 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 2002, 2001 and 2000.
Depreciation, Depletion and Amortization - Depreciation of property, plant and
equipment is provided on a straight-line basis over the estimated useful lives
of property, other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:
Annual Composite
Functional Class Depreciation Rates Ranges
of Property
2002
Production:
Steam-Nuclear 2.5% to 3.4%
Steam-Fossil-Fired 2.6% to 4.5%
Hydroelectric - Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.0%
Distribution 3.3% to 4.2%
Other 1.8% to 9.9%
Annual Composite
Functional Class Depreciation Rates Ranges
of Property
2001
Production:
Steam-Nuclear 2.5% to 3.4%
Steam-Fossil-Fired 2.5% to 4.5%
Hydroelectric - Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.1%
Distribution 2.7% to 4.2%
Other 1.8% to 15.0%
Annual Composite
Functional Class Depreciation Rates Ranges
of Property
2000
Production:
Steam-Nuclear 2.8% to 3.4%
Steam-Fossil-Fired 2.3% to 4.5%
Hydroelectric - Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.1%
Distribution 3.3% to 4.2%
Other 2.5% to 7.3%
Depreciation, depletion and amortization of coal-mining assets is provided over
each asset's estimated useful life or the estimated life of the mine, whichever
is shorter, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used to amortize
coal rights and mine development costs based on estimated recoverable tonnages.
These costs are included in the cost of coal charged to fuel expense for coal
used by utility operations. Current average amortization rates are $0.32 per ton
in 2002, $3.46 per ton in 2001 and $5.07 per ton in 2000. In 2001, an AEP
subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions,
Dispositions and Discontinued Operations for further discussion of the changes
in our coal investments leading to the decline in amortization rates for 2002.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash
investments with original maturities of three months or less.
Inventory - Except for PSO, TCC and TNC, the regulated domestic utility
companies value fossil fuel inventories using a weighted average cost method.
PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For
those domestic utilities whose generation is unregulated, inventory of coal and
oil is carried at the lower of cost or market. Coal mine inventories are also
carried at the lower of cost or market. Materials and supplies inventories are
carried at average cost.
Non-trading gas inventory is carried at the lower of cost or market. In
compliance with EITF 02-03 as described in the New Accounting Pronouncements
section of Note 1, natural gas inventories held in connection with trading
operations at October 25, 2002 continued to be carried at fair value until
December 31, 2002, and inventory purchased from October 26 through December 31,
2002 was carried at the lower of cost or market. Effective January 1, 2003, all
natural gas inventories held in connection with trading operations will be
adjusted to the historical cost basis and carried at the lower of cost or
market. We estimate the adjustment in January 2003 will decrease the value of
natural gas inventories held in connection with trading operations by
approximately $39 million. This change will be accounted for as a cumulative
effect of a change in accounting principle.
Accounts Receivable - AEP Credit Inc. factors accounts receivable for certain of
the domestic utility subsidiaries and, until the first quarter of 2002, factored
accounts receivable for certain non-affiliated utilities. On December 31, 2001
AEP Credit, Inc. entered into a sale of receivables agreement with a group of
banks and commercial paper conduits. This transaction constitutes a sale of
receivables in accordance with SFAS 140, allowing the receivables to be taken
off of the company's balance sheet. See Note 23 for further details.
Foreign Currency Translation - The financial statements of subsidiaries outside
the U.S. which are included in AEP's consolidated financial statements are
measured using the local currency as the functional currency and translated into
U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets
and liabilities are 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 in Accumulated Other Comprehensive Income (Loss). The
non-cash impact of the changes in exchange rates on cash, resulting from the
translation of items at different exchange rates is shown on AEP's Consolidated
Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual
currency transaction gains and losses are recorded in income.
Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the
fuel is burned. Where applicable under governing state regulatory commission
retail rate orders, fuel cost over-recoveries 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 $143 million at December 31, 2002 and $139
million at December 31, 2001. See also Note 7 "Effects of Regulation".
We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of
Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for
APCo. Where fuel clauses have been eliminated due to the transition to market
pricing (Ohio effective January 1, 2001 and in the Texas ERCOT area effective
January 1, 2002), changes in fuel costs impact earnings. In other state
jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have
been frozen or suspended for a period of years, fuel cost changes also impact
earnings. This is also true for certain of AEP's Independent Power Producer
generating units that do not have long-term contracts for their fuel supply. See
Note 6, "Rate Matters" and Note 8, "Customer Choice and Industry Restructuring"
for further information about fuel recovery.
Revenue Recognition -
Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo,
TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate-regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide currently for refunds to
customers that have not yet been made.
When recovery of regulatory assets is probable 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 - Revenues are recognized
on the accrual or settlement basis for normal retail and wholesale electricity
supply sales and electricity transmission and distribution delivery services.
The revenues are recognized in our income statement when the energy is delivered
to the customer and include unbilled as well as billed amounts. In general,
expenses are recorded when purchased electricity is received and when expenses
are incurred.
Domestic Gas Pipeline and Storage Activities - Revenues are recognized from
domestic gas pipeline and storage services when gas is delivered to contractual
meter points or when services are provided. Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts, excluding
wellhead purchases of natural gas, swaps and options for the domestic pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair value during the period are recognized currently in the results of
operations, appropriately discounted and net of applicable credit and liquidity
reserves.
Energy Marketing and Trading Transactions - In 2000, 2001 and throughout the
majority of 2002, AEP engaged in wholesale electricity, natural gas and other
commodity marketing and trading transactions (trading activities). Trading
activities involve the purchase and sale of energy under forward contracts at
fixed and variable prices and the trading of financial energy contracts which
includes exchange futures and options and over-the-counter options and swaps. We
use the mark-to-market method of accounting for trading activities as required
by EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" (EITF 98-10). Under the mark-to-market method of
accounting, gains and losses from settlements of forward trading contracts are
recorded net in revenues. For energy contracts not yet settled, whether physical
or financial, changes in fair value are recorded net in revenues as unrealized
gains and losses from mark-to-market valuations. When positions are settled and
gains and losses are realized, the previously recorded unrealized gains and
losses from mark-to-market valuations are reversed. In October 2002, management
announced plans to focus on wholesale markets around owned assets.
The fair values of open short-term trading contracts are based on exchange
prices and broker quotes. Open long-term trading contracts are marked-to-market
based mainly on AEP- developed valuation models. The models are derived from
internally assessed market prices with the exception of the NYMEX gas curve,
where we use daily settled prices. All fair value amounts are net of appropriate
valuation adjustments for items such as discounting, liquidity and credit
quality. Such valuation adjustments provide for a better approximation of fair
value. The use of these models to fair value open trading contracts has inherent
risks relating to the underlying assumptions employed by such models.
Independent controls are in place to evaluate the reasonableness of the price
curve models. Significant adverse or favorable effects on future results of
operations and cash flows could occur if market prices, at the time of
settlement, do not correlate with AEP-developed price models.
As explained above, the effect on AEP's Consolidated Statements of Operations of
marking to market open electricity trading contracts in AEP's regulated
jurisdictions is deferred as regulatory assets (losses) or liabilities (gains)
since these transactions are included in cost of service on a settlement basis
for ratemaking purposes. Unrealized mark-to-market gains and losses from trading
activities whether deferred or recognized in revenues are part of Energy Trading
and Derivative Contracts assets or liabilities as appropriate.
Construction Projects for Outside Parties - Certain AEP entities engage in
construction projects for outside parties that are accounted for on the
percentage-of-completion method of revenue recognition. This method recognizes
revenue in proportion to costs incurred compared to total estimated costs.
Debt Instrument Hedging and Related Activities - In order to mitigate the risks
of market price and interest rate fluctuations, AEP enters into contracts to
manage the exposure to unfavorable changes in the cost of debt to be issued.
These anticipatory debt instruments are entered into in order to manage the
change in interest rates between the time a debt offering is initiated and the
issuance of the debt (usually a period of 60 days). Gains or losses from these
transactions are deferred and amortized over the life of the debt issuance with
the amortization included in interest charges. There were no such forward
contracts outstanding at December 31, 2002 or 2001. See Note 17 - "Risk
Management, Financial Instruments and Derivatives" for further discussion of the
accounting for risk management transactions.
Levelization of Nuclear Refueling Outage Costs - In order to match costs with
regulated revenues, incremental operation and maintenance costs associated with
periodic refueling outages at I&M's Cook Plant are deferred and amortized over
the period beginning with the commencement of an outage and ending with the
beginning of the next outage.
Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS
71 requires the recordation of a regulatory asset to match the expensing of
maintenance costs with their recovery in cost-based regulated revenues. See
below for an explanation of costs deferred in connection with an extended outage
at 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 each year
1999 through 2002 leaving $40 million as a SFAS 71 Regulatory Asset at December
31, 2002 on the Consolidated Balance Sheets.
Other Income and Other Expenses - Other Income includes non-operational revenue
including area business development and river transportation, equity earnings of
non-consolidated subsidiaries, gains on dispositions of property, interest and
dividends, an allowance for equity funds used during construction (explained
above) and miscellaneous income. Other Expenses includes non-operational expense
including area business development and river transportation, losses on
dispositions of property, miscellaneous amortization, donations and various
other non-operating and miscellaneous expenses.
AEP Consolidated Other Income and Deductions
December 31,
2002 2001 2000
---- ---- ----
(in millions)
OTHER INCOME:
Equity Earnings $ 104 $ 123 $ 22
Non-operational Revenue 187 123 71
Interest and Miscellaneous
Income 25 16 2
Gain on Sale of Frontera - 73 -
Gain on Sale of Retail
Electric Provider 129 - -
----- ----- ----
Total Other Income $ 445 $ 335 $ 95
===== ===== ====
OTHER EXPENSES:
Property Taxes and
Miscellaneous Expenses $ 142 $ 68 $ 28
Non-operational Expenses 179 56 49
Fiber Optic and Datapult
Exit Costs - 49 -
Provision for Loss - Airplanes - 14 -
----- ----- ----
Total Other Expenses $ 321 $ 187 $ 77
===== ===== ====
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, as an agent for a state or local government, collects 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 Consolidated Statements of Operations.
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
their recovery in rates. Gains and losses on the reacquisition of debt for
operations not subject to SFAS 71 are reported as a Loss on Reacquired Debt, an
extraordinary item on the Consolidated Statements of Operations. See discussion
of SFAS 145 in New Accounting Pronouncements section of this note for new
treatment effective in 2003.
Debt discount or premium and debt issuance expenses are deferred and amortized
utilizing the effective interest rate method over the term of the related debt.
The amortization expense is included in interest charges.
Where rates are regulated, redemption premiums paid to reacquire preferred stock
of the domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.
Goodwill and Intangible Assets - In June 2001, the FASB issued SFAS 141,
Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets.
SFAS 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001 and established new
standards for the recognition of certain identifiable intangible assets,
separate from goodwill. We adopted the provisions of SFAS 141 effective July 1,
2001. See Note 12 for further discussion of acquisitions initiated after June
30, 2001 and Note 3 for further discussion of our components of goodwill and
intangible assets.
SFAS 142 requires that goodwill and intangible assets with finite useful lives
no longer be amortized, but instead tested for impairment at least annually.
SFAS 142 also requires that intangible assets with finite useful lives be
amortized over their respective estimated lives to the estimated residual
values. In accordance with SFAS 142, for all business combinations with an
acquisition date before July 1, 2001, we amortized goodwill and intangible
assets with indefinite lives through December 2001, and then ceased
amortization. The goodwill associated with those business combinations with an
acquisition date before July 1, 2001 was amortized on a straight-line basis
generally over 40 years except for the portion of goodwill associated with gas
trading and marketing activities which was amortized on a straight-line basis
over 10 years. In accordance with SFAS 142, for all business combinations with
an acquisition date after June 30, 2001, we have not amortized goodwill and
intangible assets with indefinite lives. Intangible assets with finite lives
continue to be amortized over their respective estimated lives ranging from 5 to
10 years. See Note 3 for total goodwill, accumulated amortization and the impact
on operations of the adoption of SFAS 142.
In early 2002, we began testing our goodwill and intangible assets with
indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3
for the results of our testing and the corresponding net transitional impairment
loss recorded as a Cumulative Effect of Accounting Change during 2002.
Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds
represent funds that regulatory commissions have allowed us to collect through
rates to fund future decommissioning and spent fuel disposal liabilities. By
rules or orders, the state jurisdictional commissions (Indiana, Michigan and
Texas) and the FERC established investment limitations and general risk
management guidelines to protect their ratepayers' funds and to allow those
funds to earn a reasonable return. In general, limitations include:
o Acceptable investments (rated investment grade or above)
o Maximum percentage invested in a specific type of investment
o Prohibition of investment in obligations of the applicable company or
its affiliates
Trust funds are maintained for each regulatory jurisdiction and managed by
investment managers, who must comply with the guidelines and rules of the
applicable regulatory authorities. The trust assets are invested in order to
optimize the after-tax earnings of the trust, giving consideration to liquidity,
risk, diversification, and other prudent investment objectives.
Securities held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are included in Other Assets at market value
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity Securities." Securities in the trust funds have been classified as
available-for-sale due to their long-term purpose. In accordance with SFAS 71,
unrealized gains and losses from securities in these trust funds are not
reported in equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or liabilities for
the spent nuclear fuel disposal trust funds in accordance with their treatment
in rates.
Comprehensive Income (Loss) - Comprehensive income 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.
Components of Other Comprehensive Income (Loss) - Other comprehensive income
(loss) is included on the balance sheet in the equity section. The following
table provides the components that comprise the balance sheet amount in
Accumulated Other Comprehensive Income (Loss) for AEP.
December 31,
Components 2002 2001 2000
-------------------------------------------------------------------------
(in millions)
Foreign Currency
Adjustments 4 $(113) $ (99)
Unrealized Losses
On Securities (2) - -
Unrealized Gain (Loss) on Hedged Derivatives (16) (3) -
Minimum Pension Liability (595) (10) (4)
----- ----- ----
$(609) $(126) $(103)
===== ===== =====
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 16 "Business Segments" for further
discussion and details regarding segments.
Common Stock Options - At December 31, 2002, AEP has two stock-based employee
compensation plans with outstanding stock options, which are described more
fully in Note 15. We account for these plans under the recognition and
measurement principles of APB Opinion No. 25, Accounting for Stock Issued to
Employees and related Interpretations. No stock-based employee compensation
expense is reflected in earnings, as all options granted under these plans had
exercise prices equal to or above the market value of the underlying common
stock on the date of grant. The following table illustrates the effect on net
income (loss) and earnings (loss) per share as if the company had applied the
fair value recognition provisions of FASB Statement No. 123, "Accounting for
Stock-Based Compensation", to stock-based employee compensation.
Year Ended December 31,
2002 2001 2000
---- ---- ----
(in millions
except per share data)
Net Income(Loss), as reported $ (519) $ 971 $ 267
Deduct: Total stock- based employee
compensation
expense determined
under fair value
based method for
all awards, net of
related tax effects (9) (12) (3)
------ ----- -----
Pro forma net income
(loss) $ (528) $ 959 $ 264
====== ===== =====
Earnings (Loss) per share:
Basic - as reported $(1.57) $3.01 $0.83
====== ===== =====
Basic - pro forma $(1.59) $2.98 $0.82
====== ===== =====
Diluted - as reported $(1.57) $3.01 $0.83
====== ===== =====
Diluted - pro forma $(1.59) $2.97 $0.82
====== ===== =====
Earnings Per Share (EPS) - AEP calculates earnings (loss) per share in
accordance with SFAS No. 128, "Earnings Per Share" (see Note 19). Basic earnings
(loss) per common share is calculated by dividing net earnings (loss) available
to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings (loss) per common share is
calculated by adjusting the weighted average outstanding common shares, assuming
conversion of all potentially dilutive stock options and awards. The effects of
stock options have not been included in the fiscal 2002 diluted loss per common
share calculation as their effect would have been anti-dilutive. Basic and
diluted EPS are the same in 2002, 2001 and 2000.
Reclassification - Beginning in the fourth quarter of 2002, AEP elected to begin
netting certain assets and liabilities related to forward physical and financial
transactions. This is done in accordance with FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts" and Emerging Issues Task
Force Topic D-43, "Assurance That a Right of Setoff is Enforceable in a
Bankruptcy under FASB Interpretation No. 39". Transactions with common
counterparties have been netted at the applicable entity level, by commodity and
type (physical or financial) where the legal right of offset exists. For
comparability purposes, prior periods presented in this report have been netted
in accordance with this policy.
Certain additional prior year financial statement items have been reclassified
to conform to current year presentation. Such reclassifications had no impact on
previously reported net income.
New Accounting Pronouncements
SFAS 142, "Goodwill and Other Intangible Assets", was effective for AEP on
January 1, 2002. The adoption of SFAS 142 required the transition testing for
impairment of all indefinite lived intangibles by the end of the first quarter
2002 and initial testing of goodwill by the end of the second quarter 2002. In
the first quarter 2002, AEP completed testing the goodwill of its domestic
operations and its indefinite lived intangible assets and there was no
impairment. In the second quarter 2002, we completed initial testing for
goodwill impairment of our U.K. and Australian retail electricity and supply
operations. The fair values of the U.K. and Australia retail electricity and
supply operations were estimated using a combination of market values based on
recent market transactions and cash flow projections. As a result of that
testing, we determined that we had a net transitional impairment loss, which is
reported as a cumulative effect of a change in accounting principle. See Notes
2, 3, 12 and 13 for further discussion of the actual impairment charges and
sales of impaired assets.
SFAS 142 also changed the accounting and reporting for goodwill and other
intangible assets. In accordance with SFAS 142 goodwill and indefinite lived
intangible assets acquired through acquisition after June 30, 2001 were not
amortized. Effective January 1, 2002, amortization related to goodwill and
indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142
requires that other intangible assets be separately identified and if they have
finite lives, they must be amortized over that life. See Note 3 for amortization
lives of our intangible assets.
SFAS 143, "Accounting for Asset Retirement Obligations", is effective for AEP on
January 1, 2003. SFAS 143 generally applies to legal obligations associated with
the retirement of long-lived assets. A company is required to recognize an
estimated liability for any legal obligations associated with the future
retirement of its long-lived assets. The liability is measured at fair value and
is capitalized as part of the related asset's capitalized cost. The increase in
the capitalized cost is included in determining depreciation expense over the
expected useful life of the asset. The catch-up effect of adopting SFAS 143 will
be recorded as a cumulative effect of an accounting change. Additionally,
because the asset retirement obligation is recorded initially at fair value,
accretion expense (similar to interest) will be recognized each period as an
operating expense in the statement of operations.
The regulated entities have an asset retirement obligation associated with
nuclear decommissioning costs for the Cook and STP Nuclear Plants and possibly
other obligations. We expect to establish regulatory assets and liabilities that
will result in no cumulative effect adjustment of adopting SFAS 143 for the
regulated entities.
In addition, the regulated transmission and distribution entities have asset
retirement obligations related to the final retirement of certain transmission
and distribution lines. There are also underground storage tanks located at
various sites throughout the AEP System and PCB's are contained in certain
transformer rectifier sets at power plants. The amounts relating to these
obligations cannot be determined because the entities are not able to estimate
the final retirement dates for these facilities.
In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity
from recording an expense for estimated costs associated with the removal or
retirement of assets that result from other than legal obligations. The SEC
Staff concluded that amounts that are included in accumulated depreciation
related to estimated removal costs arising from other than legal obligations
should be written off as part of the cumulative effect of adopting SFAS 143
unless the company is regulated under SFAS 71. Companies regulated under SFAS 71
may continue to include removal costs in depreciation rates but must quantify
the removal costs included in accumulated depreciation as regulatory liabilities
in footnote disclosure. The AEP registrant subsidiaries that are regulated
entities have included estimated removal costs for non-legal retirement
obligations in book depreciation rates.
For non-regulated entities, including certain formerly regulated generation
facilities, asset retirement obligations associated with wind farms, closure
costs associated with power plants in the U.K. and possibly other items will be
incurred. Also the amount of removal costs embedded in accumulated depreciation
is expected to result in a favorable cumulative effect adjustment to net income.
However, we have not completed our determination of the net effect of these
items on first quarter 2003 results of operations upon the adoption of the
provisions of this standard.
In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-lived Assets" which sets forth the accounting to recognize and
measure an impairment loss. This standard replaced, SFAS 121, "Accounting for
Long-lived Assets and for Long-lived Assets to be Disposed Of." AEP adopted SFAS
144 effective January 1, 2002. The adoption of SFAS 144 did not materially
affect AEP's results of operations or financial conditions. See Notes 3 and 13
for discussion of impairments recognized in 2002, affected by SFAS 144.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS
145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt",
effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains
and losses from extinguishment of debt to be aggregated and classified as an
extraordinary item if material. In 2003, for financial reporting purposes AEP
will reclassify extraordinary losses net of tax on reacquired debt of $2 million
for 2001.
In October 2002, the Emerging Issues Task Force of the FASB reached a final
consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on
Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3). EITF 02-3
rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3,
mark-to-market accounting is precluded for energy trading contracts that are not
derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also
eliminate any basis for recognizing physical inventories at fair value other
than as provided by generally accepted accounting principles. The consensus is
effective for fiscal periods beginning after December 15, 2002, and applies to
all energy trading contracts entered into and inventory purchased through
October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are
required to be accounted for on a settlement basis and inventory is required to
be presented at the lower of cost or market. The effect of implementing this
consensus will be reported as a cumulative effect of an accounting change. Such
contracts and inventory will continue to be accounted for at fair value through
December 31, 2002. Energy contracts that qualify as derivatives will continue to
be accounted for at fair value under SFAS 133.
Effective January 1, 2003, EITF 02-3 requires that gains and losses on all
derivatives, whether settled financially or physically, be reported in the
income statement on a net basis if the derivatives are held for trading
purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy
trading contracts to be reported either gross or net in the income statement.
Prior to the third quarter of 2002, we recorded and reported upon settlement,
sales under forward trading contracts as revenues and purchases under forward
trading contracts as purchased energy expenses. Effective July 1, 2002, we
reclassified such forward trading revenues and purchases on a net basis, as
permitted by EITF 98-10. The reclassification of such trading activity to a net
basis of reporting resulted in a substantial reduction in both revenues and
purchased energy expense, but did not have any impact on our financial
condition, results of operations or cash flows.
Effective July 1, 2002, we modified our valuation procedures for estimating the
fair value of energy trading contracts at inception. Unrealized gain or loss at
inception is recognized only when the fair value of a contract is obtained from
a quoted market price in an active market or is otherwise evidenced by
comparison to other observable market data. Any fair value changes subsequent to
the inception of a contract, however, are recognized immediately based on the
best market data available. We now also use such procedures for determining
unrealized gain or loss at inception for all derivative contracts.
In June 2002, FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes previous
accounting guidance, principally EITF No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. SFAS 146 requires that the liability for costs associated with
an exit or disposal activity be recognized when the liability is incurred. SFAS
146 also establishes that the liability should initially be measured and
recorded at fair value. The timing of recognizing future costs related to exit
or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. We will adopt the provisions of SFAS 146
for exit or disposal activities initiated after December 31, 2002.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45) which requires that a liability related to
issuing a guarantee be recognized, as well as additional disclosures of
guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107
and a rescission of FIN No. 34. The initial recognition and initial measurement
provisions of FIN 45 are effective on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements of FIN 45 are
effective for financial statements of interim and annual periods ending after
December 15, 2002. We do not expect that the implementation of FIN 45 will
materially affect results of operations, cash flows or financial condition. See
guarantee details discussed in Note 10.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure", which amends SFAS No. 123, "Accounting
for Stock-Based Compensation". SFAS 148 provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Under the fair value based method,
compensation cost for stock options is measured when options are issued. In
addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require
more prominent and more frequent (quarterly) disclosures in financial statements
of the effects of stock-based compensation. SFAS 148 is effective for fiscal
years ending after December 15, 2002. AEP does not currently intend to adopt the
fair value based method of accounting for stock options.
In November 2002, the FASB issued an Invitation to Comment, "Accounting for
Stock-Based Compensation: A Comparison of FASB Statement No. 123, Accounting for
Stock-Based Compensation, and Its Related Interpretations, and IASB Proposed
IFRS, Share-Based Payment." The FASB plans to make a decision in the first
quarter of 2003 whether it will begin a more comprehensive reconsideration of
the accounting for stock options. This may include revisiting the decision in
SFAS 123 allowing companies to disclose the pro forma effects of the fair value
based method rather than requiring recognition of the fair value of employee
stock options as an expense.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which changes the requirements for
consolidation of certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This new guidance is an
interpretation of Accounting Research Bulletin (ARB) No. 51, "Consolidated
Financial Statements". The initial recognition and initial measurement
provisions of FIN 46 for all enterprises with variable interests in variable
interest entities created after January 31, 2003, shall apply the provisions of
this Interpretation to those entities immediately. A public entity with variable
interests in variable interest entities created before February 1, 2003 shall
apply the provisions of this Interpretation no later than the beginning of the
first interim or annual reporting period beginning after June 15, 2003.
If it is reasonably possible that an enterprise will consolidate or disclose
information about a variable interest entity when this Interpretation becomes
effective, the enterprise shall disclose the following information in all
financial statements initially issued after January 31, 2003, regardless of the
date on which the variable interest entity was created:
a. The nature, purpose, size, and activities of the variable interest entity
b. The enterprise's maximum exposure to loss as a result of its involvement
with the variable interest entity
AEP believes it is reasonably possible that it will be required to consolidate
identified variable interest entities as a result of this new guidance. See
Notes 9, 22, 23 and 26 for additional disclosures relating to AEP's variable
interest entities.
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
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. In April 2002 the Ohio Supreme Court denied recovery of the final year of
the GRT.
In October 2001 TCC reacquired $101 million of pollution control bonds in
advance of their maturity. Since these pollution control bonds were used to
finance unregulated generation assets, a loss of $2 million after-tax was
recorded. The Company had no extraordinary items in 2002.
The following table shows the components of the extraordinary items reported on
the consolidated statements of operations:
Year Ended
December 31,
-------------
2002 2001 2000
---- ---- ----
(in millions)
Extraordinary Items:
Discontinuance of Regulatory
Accounting for Generation:
Ohio Jurisdiction (Net of Tax
of $20 million in 2001 and
$35 Million in 2000) $ - $(48) $(44)
Virginia and West Virginia
Jurisdictions (Inclusive of
Tax Benefit of $8 Million) - - 9
Loss on Reacquired Debt
(Net of Tax of $1 Million
in 2001) - (2) -
---- ---- ----
Extraordinary Items $ - $(50) $(35)
==== ==== ====
Cumulative Effect of Accounting Change - SFAS 142 requires that goodwill and
intangible assets with indefinite useful lives no longer be amortized and be
tested annually for impairment. The implementation of SFAS 142 resulted in a
$350 million net transitional loss for our U.K. and Australian operations and is
reported in the Consolidated Statements of Operations as a cumulative effect of
accounting change (see Note 3 for further details).
The FASB's Derivative Implementation Group (DIG) issued accounting guidance
under SFAS 133 for certain derivative fuel supply contracts with volumetric
optionality and derivative electricity capacity contracts. This guidance,
effective in the third quarter of 2001, concluded that fuel supply contracts
with volumetric optionality cannot qualify for a normal purchase or sale
exclusion from mark-to-market accounting and provided guidance for determining
when certain option-type contracts and forward contracts in electricity can
qualify for the normal purchase or sale exclusion.
For AEP, the effect of initially adopting the DIG guidance at July 1, 2001 was a
favorable earnings mark-to-market effect of $18 million, net of tax of $2
million. It was reported as a cumulative effect of an accounting change on the
consolidated statements of operations.
3. Goodwill and Other Intangible Assets:
As described in our Significant Accounting Policies footnote, we adopted the
provisions of SFAS 141 effective July 1, 2001. SFAS 141 requires that the
purchase method of accounting be used for all business combinations initiated
after June 30, 2001 and established new standards for the recognition of certain
identifiable intangible assets, separate from goodwill. Business combinations
initiated after June 30, 2001 (see Note 12 for details) are accounted for
utilizing SFAS 141.
SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized, but instead tested for impairment at least
annually. SFAS 142 required a two-step impairment test for goodwill. The first
step was to compare the carrying amount of the reporting unit's assets to the
fair value of the reporting unit. If the carrying amount exceeded the fair value
then the second step was required to be completed, which involves allocating the
fair value of the reporting unit to each asset and liability, with the excess
being implied goodwill. The impairment loss is the amount by which the recorded
goodwill exceeds the implied goodwill. We were required to complete a
"transitional" impairment test for goodwill as of the beginning of the fiscal
year in which the statement was adopted. This transitional impairment test
required that we complete step one of the goodwill impairment test within six
months from the date of initial adoption, or June 30, 2002. In the first quarter
2002, we completed the transitional impairment test of our goodwill related to
our domestic operations and our indefinite lived intangible assets and concluded
that those assets were not impaired.
In the second quarter 2002, we completed testing for goodwill impairment on our
U.K. and Australian retail electricity and supply operations. The fair values of
our U.K. and Australian retail electricity and supply operations were estimated
using a combination of market values based on recent market transactions and
cash flow projections. As a result of this testing, we determined that we had a
net transitional impairment loss of $350 million, which is reported in the
Consolidated Statements of Operations as a Cumulative Effect of Accounting
Change.
SFAS 142 also requires that intangible assets with finite useful lives be
amortized over their respective estimated lives to the estimated residual
values. In accordance with SFAS 142, for all business combinations initiated
before July 1, 2001, we amortized goodwill and intangible assets with indefinite
lives through December 2001, and then ceased amortization. The goodwill
associated with those business combinations with acquisition dates before July
1, 2001 was amortized on a straight-line basis generally over 40 years except
for the portion of goodwill associated with gas trading and marketing
activities, which was amortized on a straight-line basis over 10 years. Also, in
accordance with SFAS 142, for all business combinations with acquisition dates
after June 30, 2001, we have not amortized goodwill and intangible assets with
indefinite lives. Intangible assets with finite lives continue to be amortized
over their respective estimated lives ranging from 5 to 10 years.
New reporting requirements imposed by SFAS 142 include the disclosures shown
below.
Goodwill
The changes in the carrying amount of goodwill for the twelve months ended
December 31, 2002 by operating segment are:
Energy AEP
Wholesale Delivery Other Consolidated
--------- -------- ----- ------------
(in millions)
Balance January 1, 2002 $340 $37 $15 $392
Goodwill acquired 2 - - 2
Changes to Goodwill due to purchase price
adjustments 181 - - 181
Non-transitional impairment losses (173) - (12) (185)
Foreign currency exchange rate changes 6 - - 6
---- --- --- ----
Balance December 31, 2002 $356 $37 $ 3 $396
==== === === ====
Accumulated amortization of goodwill was approximately $22 million and $25
million at December 31, 2002 and 2001, respectively. A decrease of $3 million
related principally to the non-transitional impairment of goodwill on Gas Power
Systems (see Note 13.a).
The transitional impairment loss related to SEEBOARD and CitiPower goodwill,
which is reported as a cumulative effect of an accounting change, is excluded
from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower,
including goodwill and acquired intangible assets no longer subject to
amortization, are reported as Assets of Discontinued Operations in the
Consolidated Balance Sheets. See Note 12 related to the sale of SEEBOARD and
CitiPower.
Changes to goodwill due to purchase price adjustments of $181 million was
primarily due to purchase price adjustments related to our acquisition of U.K.
Generation. The purchase price adjustments also include adjustments related to
the acquisition of Houston Pipe Line Company, MEMCO, Nordic Trading and AEP Coal
(see Note 12).
In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12
million for all goodwill related to the acquisition of Gas Power Systems (see
Note 13.a).
In the fourth quarter of 2002, AEP prepared its annual goodwill impairment
tests. The fair values of the operations were estimated using cash flow
projections. There were no goodwill impairments as a result of the annual
goodwill impairment tests. However, in the fourth quarter, AEP recognized
goodwill impairment losses totaling $173 million related to impairment studies
performed on the U.K. Generation assets ($166 million), AEP Coal ($3 million),
and Nordic Trading ($4 million). These goodwill impairment studies were
triggered by the SFAS 144 asset impairment losses recognized on these operations
in the fourth quarter (refer to Note 13). The fair values of these operations
were estimated using cash flow projections.
The following tables show the transitional disclosures to adjust reported net
income (loss) and earnings (loss) per share to exclude amortization expense
recognized in prior periods related to goodwill and intangible assets that are
no longer being amortized.
Net Income (Loss) Year Ended December 31,
-----------------------
2002 2001 2000
---- ---- ----
(in millions)
Reported Net Income (Loss) $ (519) $ 971 $267
Add back: Goodwill amortization (a) - 39 39
Add back: Amortization for intangibles with indefinite
lives under SFAS 142 (b) - 8 9
------ ------ ----
Adjusted Net Income (Loss) $ (519) $1,018 $315
====== ====== ====
Twelve Months Ended
Earnings (Loss) Per Share (Basic and Dilutive) December 31,
2002 2001 2000
---- ---- ----
Reported Earnings (Loss) per Share $(1.57) $3.01 $0.83
Add back: Goodwill amortization (c) - 0.12 0.12
Add back: Amortization for intangibles with
indefinite lives under SFAS 142 (d) - 0.02 0.03
------ ----- -----
Adjusted Earnings (Loss) per Share $(1.57) $3.15 $0.98
====== ===== =====
(a) This amount includes $34 million and $37 million in 2001 and 2000 related
to Seeboard and CitiPower amortization expense included in Discontinued
Operations on the Consolidated Statements of Operations.
(b) The amounts shown for 2001 and 2000 relate to CitiPower amortization
expense included in Discontinued Operations on the Consolidated
Statements of Operations.
(c) This amount includes $0.10 and $0.11 in 2001 and 2000 related to Seeboard
and CitiPower amortization expense included in Discontinued Operations on
the Consolidated Statements of Operations.
(d) The amounts shown for 2001 and 2000 relate to CitiPower amortization
expense included in Discontinued Operations on the Consolidated
Statements of Operations.
Acquired Intangible Assets
Acquired intangible assets subject to amortization are $37 million at December
31, 2002 and $33 million at December 31, 2001, net of accumulated amortization.
The gross carrying amount, accumulated amortization and amortization life by
major asset class are:
December 31, 2002 December 31, 2001
Gross Gross
Amortization Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------ -------- ------------ ------- ------------
(in years) (in millions) (in millions)
Dolet Hills Advanced
Royalties 10 $35 $5 $35 $2
Less: Adjustment Due to
Purchase
Price 6 1 - -
Reallocation
Trade name and
Administration of
Contracts 7 2 - - -
Unpatented
Technology 10 10 - - -
--- -- --- --
Totals $41 $4 $35 $2
=== == === ==
Amortization of intangible assets was $2 million for the twelve months ended
December 31, 2002. Estimated aggregate amortization expense is $4 million for
each year 2003 through 2008.
AEP's acquired intangible assets no longer subject to amortization were
comprised of retail and wholesale distribution licenses for CitiPower operating
franchises. The licenses were being amortized on a straight-line basis over 20
and 40 years for the retail and wholesale licenses, respectively. In accordance
with SFAS 144, the assets of CitiPower, including acquired intangible assets no
longer subject to amortization, are reported as Assets of Discontinued
Operations on one line in the Consolidated Balance Sheets. See Note 12 related
to the sale of CitiPower.
4. 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.
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. Effective January 2003, the legal name of CSW was
changed to AEP Utilities, Inc.
In connection with the merger, $10 million ($7 million after tax), $21 million
($14 million after tax) and $203 million ($180 million after tax) of
non-recoverable merger costs were expensed in 2002, 2001 and 2000. Such costs
included transaction and transition costs not recoverable from ratepayers. Also
included in the merger costs were non-recoverable changes in control payments.
Merger transaction and transition costs of $52 million recoverable from
ratepayers were deferred pursuant to state regulator approved settlement
agreements through December 31, 2002. The deferred merger costs are being
amortized over five to eight year recovery periods, depending on the specific
terms of the settlement agreements, with the amortization ($8 million, $8
million and $4 million for the years 2002, 2001 and 2000) included in
depreciation and amortization expense.
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 provisions of Merger Rate Agreements:
State/Company Ratemaking Provisions
------------- ---------------------
Texas - SWEPCo, TCC, TNC $221 million rate reduction over 6 years.
No base rate increases for 3 years post merger.
Indiana - I&M $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.
Michigan - I&M Customer billing credits of approximately $14
million over 8 years. Extension of base rate freeze
until January 1, 2005.
Kentucky - KPCo Rate reductions of approximately $28 million
over 8 years. No base rate increases for 3 years post
merger.
Oklahoma - PSO Rate reductions of approximately $28 million
over 5 years. No base rate increase before January 1,
2003.
Arkansas - SWEPCo Rate reductions of $6 million
over 5 years.
Louisiana - SWEPCo 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.
See Note 9, "Commitments and Contingencies" for information on a court decision
concerning the merger.
5. Nuclear Plant Restart:
I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant
is a 2,110 MW two-unit plant owned and operated by 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:
o Deferral of $200 million of non-fuel nuclear operation and maintenance
(O&M) costs for amortization over five years ending December 31, 2003
o Deferral of certain unrecovered fuel and power supply costs for
amortization over five years ending December 31, 2003
o A freeze in base rates through December 31, 2003 and a fixed fuel
recovery charge through March 1, 2004 in the Indiana jurisdiction,
o A freeze in base rates and fixed power supply costs recovery
factors until January 1, 2004 for the Michigan jurisdiction
The amount of costs and deferrals charged to other operation and maintenance
expenses were as follows:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Costs Incurred $ - $ 1 $ 297
Amortization of Deferrals 40 40 40
--- ---- -----
Charged to O&M Expense $40 $41 $ 337
=== === =====
At December 31, 2002 and 2001, deferred O&M costs of $40 million and $80
million, respectively, remained in Regulatory Assets to be amortized through
2003. Also pursuant to the settlement agreements, accrued fuel-related revenues
of $38 million were amortized as a reduction of revenues in each of 2002, 2001
and 2000. At December 31, 2002 and 2001, fuel-related revenues of $37 million
and $75 million, respectively, were included in Regulatory Assets and will be
amortized through December 31, 2003 for both jurisdictions.
The amortization of O&M costs and fuel-related revenues deferred under Indiana
and Michigan retail jurisdictional settlement agreements will adversely affect
results of operations through December 31, 2003 when the amortization period
ends. The annual amortization of O&M costs and fuel-related revenue deferrals is
approximately $78 million.
6. Rate Matters:
Texas Fuel -Prior to the start of retail competition in ERCOT on January 1,
2002, fuel recovery for Texas utilities was a multi-step procedure. When fuel
costs changed, utilities filed with the PUCT for authority to adjust fuel
factors. If a utility's prior fuel factors resulted in material over-recovery or
under-recovery of fuel costs, the utility would also request a refund or
surcharge factor to refund or collect those amounts. While fuel factors were
intended to recover fuel costs, final settlement of these amounts was subject to
reconciliation and approval by the PUCT.
Fuel reconciliation proceedings determine whether fuel costs incurred during the
reconciliation period were reasonable and necessary. All fuel costs incurred
since the prior reconciliation date are subject to PUCT review and approval. If
material amounts are determined to be unreasonable and ordered to be refunded to
customers, results of operations and cash flows would be negatively impacted.
According to Texas Restructuring Legislation, fuel costs in the Texas
jurisdiction after 2001 is no longer subject to PUCT review and reconciliation.
During 2002 TCC and TNC filed final fuel reconciliations with the PUCT to
reconcile their fuel costs through the period ended December 31, 2001. The
ultimate recovery of deferred fuel balances at December 31, 2001 will be decided
as part of their 2004 true-up proceedings. See discussion of TCC and TNC final
fuel reconciliations below.
In October 2001 the PUCT delayed the start of customer choice in the SPP area of
Texas. All of SWEPCo's Texas service territory and a small portion of TNC's
service territory are in SPP. SWEPCo's existing Texas fuel cost recovery
procedures will continue until competition begins. SWEPCo will continue to set
fuel factors and determine final fuel costs in fuel reconciliation proceedings
during the SPP delay period. The PUCT has ruled that TNC fuel factors in the SPP
area will be based upon the price-to-beat fuel factors offered by the retail
electric provider in the ERCOT portion of TNC's service territory. TNC
transferred its SPP customers to Mutual Energy SWEPCo effective December 1,
2002. TNC filed in 2002 with the PUCT to determine the most appropriate method
to reconcile fuel costs in TNC's SPP area and a decision is expected by mid
2003.
Under Texas restructuring, customer choice to select a retail electric provider
began January 1, 2002. Sales to customers using 1 MW or less are at fixed base
rates during a transition period from 2002 through 2006. As discussed in Note 12
"Acquisitions, Dispositions and Discontinued Operations", AEP sold its Texas
retail electric providers (REP) and their retail customers in December 2002.
The former AEP subsidiaries serving as REPs for the ERCOT area filed with the
PUCT in May 2002 to increase the fuel portion of their price-to-beat rate in
compliance with the Texas Restructuring Legislation and the PUCT's rules. The
Texas legislation provides for the adjustment of the fuel portion of the rate up
to twice annually to reflect significant changes in the market price of natural
gas and purchased energy used to serve retail customers using NYMEX natural gas
prices. On July 15, 2002, the PUCT required further hearings to reconsider the
validity of their existing rules for fuel factor adjustments. On July 24, 2002,
the Texas REPs filed a petition with the District Court seeking an injunction
commanding the PUCT to proceed to a final order based on the existing rules and
prohibiting the PUCT from conducting a remand proceeding. The District Court
issued an order on August 9, 2002 requiring the PUCT to comply with the existing
rules. On August 26, 2002, the PUCT issued an order approving a 22% increase to
the fuel portion of the price-to-beat rates effective immediately for both REPs.
The PUCT order approving the 22% increase has been appealed by parties opposing
the price-to-beat adjustment. With the sale of the REPs to Centrica in December
2002, Centrica is responsible for these appeals. Any adverse ruling from the
appeal could impact TCC and TNC by requiring refunds for the time period AEP
served the retail customers prior to the sale to Centrica (January 2002 to
December 2002).
TCC Fuel Reconciliation - In December 2002 TCC filed with the PUCT to reconcile
fuel costs and to defer its over-recovery of fuel for inclusion in the 2004
true-up proceeding. This reconciliation for the period of July 1998 through
December 2001 will be the final fuel reconciliation. At December 31, 2001, the
over-recovery balance for TCC was $63.5 million including interest. During the
reconciliation period, TCC incurred $1.6 billion of eligible fuel and
fuel-related expenses. Recommendations from intervening parties are expected in
April 2003 with hearings scheduled in May 2003. A final order is expected in
late 2003. An adverse ruling from the PUCT could have a material impact on
future results of operations, cash flows and financial condition. Additional
information regarding the 2004 true-up proceeding for TCC can be found in Note 8
"Customer Choice and Industry Restructuring".
TNC Fuel Reconciliation - In June 2002 TNC filed with the PUCT to reconcile fuel
costs and to defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 2000 through December 2001 will be the
final fuel reconciliation for TNC's ERCOT service territory. At December 31,
2001, the under-recovery balance associated with TNC's ERCOT service area was
$27.5 million including interest. During the reconciliation period, TNC incurred
$293.7 million of eligible fuel costs serving both ERCOT and SPP retail
customers. TNC also requested authority to surcharge its SPP customers. TNC's
SPP customers will continue to be subject to fuel reconciliations until
competition begins in SPP. The under-recovery balance at December 31, 2001 for
TNC's service within SPP was $0.7 million including interest.
In October 2002 the filing was split into two phases for hearing purposes. The
first phase examined all components of the filing except for AEP trading
activities and the associated margins that flow back to customers as an offset
to fuel costs consistent with the PUCT - approved Texas merger settlement.
Intervenors filed testimony in the first phase recommending that up to $25
million of TNC's requested retail eligible fuel recovery be disallowed and
hearings were held on October 23, 2002. TNC disputed the recommendations. On
October 21, 2002, the PUCT Staff and Office of Public Utility Counsel (OPC)
filed a joint Motion for Summary Decision related to the second phase issue and
requested that approximately $18.5 million of TNC's retail eligible fuel
recovery be disallowed without a hearing. On November 8, 2002, the
administrative law judges (ALJs) in the case denied the motion. The intervenors
filed testimony on October 29, 2002 in the second phase recommending that up to
$34 million of TNC's requested retail eligible fuel recovery be disallowed. The
intervenors recommended disallowance includes the amount sought in the October
21 Motion for Summary Decision. The total intervenor recommended retail
disallowance is approximately $59 million. Hearings for the second phase were
held on November 13-14, 2002. On February 3, 2003, TNC filed a motion to reopen
the evidentiary record and include a decrease to retail eligible fuel costs of
$1.3 million, including interest, to reflect final resettlement revenues and
expenses from ERCOT for the period August through December 2001 (see discussion
in Fuel and Purchased Power below). The PUCT is expected to issue a final order
in this case by mid 2003. An adverse ruling from the PUCT could have a material
impact on future results of operations, cash flows and financial condition.
ERCOT Over-scheduling - ERCOT began serving as a central control center for all
of ERCOT at the end of July 2001 when ERCOT became a single control area.
Qualified scheduling entities (QSE) schedule loads and resources for ERCOT
market participants including power generation companies and retail electric
providers. In August 2001 ERCOT incurred substantial costs for managing
transmission in its north zone. The costs incurred by ERCOT to manage congestion
are shared by all ERCOT QSEs. In late 2001, the PUCT initiated an investigation
of the impact of scheduling of electric loads and resources by QSEs during
August 2001. The PUCT's investigation determined that a substantial amount of
the congestion charges were the result of QSEs, including AEP's QSE, scheduling
more resources than required to meet their actual load requirements in the ERCOT
north zone. AEP's QSE over-scheduled resources due to an error in the allocation
of estimated load requirements between ERCOT congestion zones. Pursuant to the
PUCT's investigation, QSEs, including AEP's QSE, agreed to a settlement that
provides for the refund of payments received for adjusting resource schedules
for congestion. The settlement was approved by the PUCT in November 2002. The
settlement recognizes that the scheduling errors were associated with the start
up of the ERCOT competitive market. AEP's QSE paid $3.2 million to ERCOT and
received $1.7 million from ERCOT in congestion refunds for a net payment of $1.5
million. Payments were assigned to TNC and the refunds were allocated to TCC and
TNC. TNC incurred a net cost of $2.8 million and TCC received a refund of $1.3
million. The TNC payment and TCC refund have been reflected in the final fuel
reconciliation filings for each company. However, intervening parties have
objected to the inclusion of the TNC payment in its final fuel reconciliation.
Recommendations from intervening parties in the TCC proceeding are not expected
until April 2003. An adverse ruling from the PUCT could impact future results of
operations, cash flows and financial condition.
Texas Transmission Rates - On June 28, 2001, the Supreme Court of Texas ruled
that the transmission pricing mechanism created by the PUCT in 1996 and used for
the period January 1, 1997 through August 31, 1999 was invalid. The court upheld
an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its
statutory authority to set such rates during that period. TCC and TNC were not
parties to the case. However, the companies' transmission sales and purchases
were priced using the invalid rates. It is unclear what action the PUCT will
take to respond to the court's ruling. If the PUCT changes rates retroactively,
the result could have a material unfavorable impact on results of operations and
cash flows for TCC and TNC.
FERC Wholesale Fuel Complaints - In May 2000 certain TNC wholesale customers
filed a complaint with FERC alleging that TNC had overcharged them through the
fuel adjustment clause for certain purchased power costs related to 1999
unplanned outages at TNC's Oklaunion generation station. In November 2001
certain TNC wholesale customers filed an additional complaint with the FERC
asserting that since 1997 TNC had billed wholesale customers for not only the
1999 Oklaunion outage costs, but also certain additional costs that are not
permissible under the fuel adjustment clause.
In December 2001 FERC issued an order requiring TNC to refund, with interest,
amounts associated with the May 2000 complaint that were previously billed to
wholesale customers. The effects of this order were recorded in 2001. In
response to the November 2001 complaint, negotiations to settle the complaint
and revise the contracts are continuing. In March 2002 TNC recorded a provision
for refund of $2.2 million before income taxes. The actual refund and final
resolution of this matter could differ materially from this estimate and may
have a negative impact on future results of operations, cash flow and financial
condition.
FERC Transmission Rates - In November 2001 FERC issued an order resulting from a
remand by an appeals court of a tariff compliance filing order issued in 1998
that had been appealed by certain customers. The order required PSO, SWEPCo, TCC
and TNC to submit revised open access transmission tariffs and calculate and
issue refunds for overcharges from January 1, 1997. In July 2002 FERC approved a
revised open access transmission tariff and refunds of $1.3 million were issued.
Fuel and Purchased Power - PSO had under-recovered fuel costs of $75.7 million
at December 31, 2002, representing fuel and purchased power costs recorded but
not yet collected from retail customers in Oklahoma. The first significant item
causing the under-recovery is approximately $44 million in reallocation of
purchased power costs for periods prior to January 1, 2002, as described below.
The other significant item impacting the under-recovered fuel costs are natural
gas price increases that were not expected when PSO set its quarterly factors
during 2002. The Corporation Commission of the State of Oklahoma (OCC) is
currently reviewing the reasons for the large under-recovered balance.
The AEP West electric operating companies' power is dispatched real-time on an
economic basis and is later allocated among the AEP West electric operating
companies using the Interchange Cost Reconstruction (ICR) system based on
dispatch information from internal and external sources. ICR is designed to
allocate the cost of power under the terms and conditions of the AEP West
Operating Agreement. During 2002, two ICR adjustments were made. The adjustments
were related to a 2002 true-up and a reallocation of years prior to 2002.
During the third quarter of 2002, AEP reallocated purchased power costs among
the four AEP West electric operating companies for the periods prior to January
1, 2002 (the ICR Adjustments). The effects of the reallocation on pretax income
were insignificant to PSO and TCC and increased pre-tax income at SWEPCo and TNC
by $2.4 million and $1.9 million, respectively.
The formation of the ERCOT single control zone increased the need for data
estimation and true-up which has resulted in extended true-up periods associated
with allocations being performed on estimated data. ERCOT can make adjustments
to companies' settlements for up to six months. A true-up process for 2002 was
completed and recorded in the fourth quarter of 2002 resulting in insignificant
changes in PSO's and SWEPCo's pre-tax income. TCC's pre-tax income was reduced
by $3.7 million and TNC's pre-tax income was increased by $4.8 million. As ERCOT
notifies the companies of further adjustments, they will be recorded.
PSO implemented new fuel rates in December 2002 following the OCC's review and
approval.
The new fuel factors were designed to recover estimated fuel costs for the next
three months and to begin recovery of the under-recovered amount. Recovery of
the under-recovered amount is expected to occur over several months and is
subject to OCC review and approval.
For SWEPCo, the true-up process described above and the ICR Adjustments resulted
in a net increase in fuel costs recoverable from customers of $8 million
included in Regulatory Assets on the Consolidated Balance Sheets. The amount is
recoverable from customers pursuant to the applicable fuel recovery mechanisms
and review of the state regulatory commissions in Arkansas, Louisiana and Texas.
To the extent the OCC and/or the AEP West Commissions regulating SWEPCo do not
permit recovery of the revised fuel and purchased power costs, there could be an
adverse effect on results of operations and cash flows.
PSO Rate Review - In February 2003, the Director of the OCC filed an application
requiring PSO to file all documents necessary for a general rate review before
August 1, 2003. Management is unable to predict the result of this review as the
documents and data have not been assembled.
Louisiana Compliance Filing - On October 15, 2002, SWEPCo filed with the
Louisiana Public Service Commission (LPSC) detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of their order
approving the merger between AEP and CSW. The LPSC's merger order also provides
that SWEPCo's base rates are capped at the present level through mid 2005. The
filing indicates that SWEPCo's current rates should not be reduced. If the LPSC
disagrees with our conclusion, they could order SWEPCo to file all documents for
a full cost of service revenue requirement review in order to determine whether
SWEPCo's capped rates should be reduced which would adversely impact results of
operations and cash flows.
FERC Long-term Contracts - In September 2002 the FERC voted to hold hearings to
consider requests from certain wholesale customers located in Nevada and
Washington to break long-term contracts which the customers allege are
"high-priced". At issue are long-term contracts entered during the California
energy price spike in 2000 and 2001. The complaints allege that AEP sold power
at unjust and unreasonable prices. The FERC delayed hearings to allow the
parties to hold settlement discussions. In January 2003 the FERC settlement
judge assigned to the case indicated that the parties' settlement efforts were
not progressing and he recommended that the complaint be placed back on the
schedule for a hearing. In February 2003 AEP and one of our customers agreed to
terminate their contract with the customer withdrawing its FERC complaint.
In the similar complaint, a FERC administrative law judge (ALJ) ruled in favor
of AEP and dismissed in December 2002 a complaint filed by two Nevada utilities.
In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery.
In late 2001 the utilities filed complaints that the prices for power supplied
under those contracts should be lowered because the market for power was
allegedly dysfunctional at the time such contracts were entered. The ALJ
rejected the utilities' complaint, held that the markets for future delivery
were not dysfunctional, and that the utilities' had failed to demonstrate that
the public interest required that changes be made to the contracts. The ALJ's
order is preliminary and is subject to review by the FERC. The FERC will likely
rule on the ALJ's order in 2003. Management is unable to predict the outcome of
these proceedings or their impact on results of operations.
Environmental Surcharge Filing - In September 2002 KPCo filed with the KPSC to
revise its environmental surcharge tariff to recover the cost of emissions
control equipment being installed at Big Sandy Plant. See NOx Reductions in Note
9 "Commitments and Contingencies".
The surcharge request, as filed, would increase annual revenues by approximately
$21 million and must be approved by the KPSC before its inclusion in customers'
bills. If the KPSC does not approve an increase in the environmental surcharge,
results of operations and cash flows would be negatively impacted.
7. Effects of Regulation:
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 Indiana, Kentucky, Louisiana, Michigan, Oklahoma and
Tennessee.
When the generation portion of the Company's business in Arkansas, Ohio, Texas,
Virginia and West Virginia no longer met the requirements to apply SFAS 71, net
regulatory assets were written off for that portion of the business unless they
were determined to be recoverable as a stranded cost through regulated
distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In
the Ohio and West Virginia jurisdictions generation-related regulatory assets
that are recoverable through transition rates have been transferred to the
distribution portion of the business and are being amortized as they are
recovered through charges to regulated distribution customers. These assets are
classified as "transition regulatory assets". As discussed in Note 8, "Customer
Choice and Industry 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. These assets are also classified as "transition regulatory assets." The
Texas jurisdiction generation-related regulatory assets that are eligible for
recovery through securitization have been classified as "regulatory assets
designated for or subject to securitization." See Note 8 "Customer Choice and
Industry Restructuring" for further details.
AEP's recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
-----------
2002 2001
---- ----
(in millions)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 791 $ 814
Transition Regulatory Assets 743 847
Regulatory Assets
Designated for or Subject to
Securitization 336 959
Texas Wholesale Clawback (a) 262 -
Deferred Fuel Costs 143 139
Unamortized Loss on
Reacquired Debt 83 99
Cook Plant Restart Costs 40 80
DOE Decontamination and
Decommissioning
Assessment 26 31
Other 264 193
------ ------
Total Regulatory Assets $2,688 $3,162
====== ======
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 455 $ 491
Texas Retail Clawback (a) 66 -
Other 419 393
------ -----
Total Regulatory Liabilities $ 940 $ 884
====== =====
(a) See "Texas Restructuring" section of Note 8.
At December 31, 2002 $1,870 million of Regulatory Assets are not earning a
return.
o $641 million of the total $791 million for amounts due from customers for
future income taxes are not earning a return. These balances are reversed
as the associated deferred tax timing differences are reversed, and have no
specific amortization period.
o Transition regulatory assets of $743 million are not earning a return
and had the following recovery periods.
- $419 million five years
- $205 million six years
- $119 million nine years
o Deferred fuel costs of $143 million includes $113 million that was not
earning a return and had the following recovery periods:
- $76 million that fluctuates month to month and has no fixed
recovery period.
- $37 million one year
o Cook plant restart costs of $40 million does not earn a return and has a
recovery period of one year.
o Unamortized loss on reacquired debt includes $43 million not earning a
return and ranges from one to thirty-six years recovery period.
o The balance of $289 million not earning a return is of varying natures and
recovery periods.
8. Customer Choice and Industry Restructuring:
Customer choice allowing retail customers to select alternative generation
suppliers began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan,
Virginia and in the ERCOT area of Texas. Customer choice in the SPP area of
Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT.
AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in Arkansas, Oklahoma, and West Virginia
to allow retail customers to choose their electricity supplier has been delayed
or repealed. In 2001 Oklahoma delayed implementation of customer choice
indefinitely. In February 2003 the Arkansas General Assembly passed legislation
that repealed customer choice legislation, which is currently awaiting signature
by the Governor of Arkansas. Before West Virginia's choice plan can be
effective, tax legislation must be passed to continue consistent funding for
state and local governments. No further legislation has been introduced related
to restructuring in West Virginia.
In general, state restructuring legislation provides for a transition from
cost-based rate regulated bundled electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier.
Ohio Restructuring - Customer choice of electricity supplier and restructuring
began on January 1, 2001, under the Ohio Act. At January 1, 2003, virtually all
customers continue to receive supply service from CSPCo and OPCo with a
legislatively required residential generation rate reduction of 5%. All
customers continue to be served by CSPCo and OPCo for transmission and
distribution services.
The Ohio Act provided for a five-year transition period to move from cost-based
rates to market pricing for electric generation supply services. It granted the
PUCO broad oversight responsibility for promulgation of rules for competitive
retail electric generation service and approval of a transition plan for each
electric utility company, changed the taxation of electric companies and
addressed certain major transition issues including unbundling of rates and the
recovery of stranded costs including regulatory assets and transition costs.
In 1999 CSPCo and OPCo filed transition plans. After negotiations with
interested parties including the PUCO staff, the PUCO approved a stipulation
agreement for CSPCo's and OPCo's transition plans. The approved plans included,
among other things, recovery of generation-related regulatory assets over seven
years for OPCo and over eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and through a wires charge for
the remaining years. At December 31, 2002, the remaining amount of regulatory
assets to be amortized as recovered was $375 million for OPCo and $205 million
for CSPCo.
By provisions of the Ohio Act on May 1, 2001, electric distribution companies
became subject to an excise tax based on KWH sold to Ohio customers. The last
tax year for which Ohio electric utilities paid the excise tax based on gross
receipts was May 1, 2001 through April 30, 2002. As required by law, the gross
receipts tax is paid in advance of the tax year for which the utility exercises
its privilege to conduct business. CSPCo and OPCo treated the tax payment as a
prepaid expense and amortized it to expense during the privilege year.
The stipulation agreement also required the PUCO to consider implementation of a
gross receipts tax credit rider as the parties could not reach an agreement.
Following a hearing on the gross receipts tax issue, the PUCO ordered the gross
receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as
proposed by the companies. On April 3, 2002, the Ohio Supreme Court rejected the
companies' arguments and affirmed the PUCO's order which established the
effective date of tax credit riders in rates. This ruling had no impact on 2002
results of operations as the companies had recorded an extraordinary loss of $48
million (net of tax of $20 million) in 2001.
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio
and American Municipal Power - Ohio filed a complaint with the PUCO alleging
that CSPCo and OPCo have violated the PUCO's orders regarding implementation of
their transition plan and violated other applicable law by failing to
participate in an RTO.
The complainants seek, among other relief, an order from the PUCO suspending
collection of transition charges by CSPCo and OPCo until transfer of control of
their transmission assets has occurred, pricing standard offer electric
generation effective January 1, 2006 at the market price used by the companies
in their 1999 transition plan filings to estimate transition costs and imposing
a $25,000 per company forfeiture for each day AEP fails to comply with its
commitment to transfer control of transmission assets to an RTO.
Due to the FERC's reversal of its previous approvals of our RTO filings, CSPCo
and OPCo have been delayed in the implementation of their RTO participation
plans. We continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, the companies filed an
application with PUCO for approval of the transfer of functional control over
certain of their transmission facilities to PJM. Management is unable to predict
the timing of FERC's final approval of RTOs, the timing of an RTO being
operational or the outcome of these proceedings before the PUCO.
In October 2002 the PUCO initiated an investigation of the financial condition
of Ohio's regulated public utilities. The PUCO's goal is to identify measures
available to the PUCO to ensure that the regulated operations of Ohio's public
utilities are not impacted by adverse financial consequences of parent or
affiliate company unregulated operations and take appropriate corrective action,
if necessary. The utilities and other interested parties were requested to
provide comments and suggestions by November 12, 2002, with reply comments by
November 22, 2002, on the type of information necessary to accomplish the stated
goals, the means to gather the required information from the public utilities
and potential courses of action that the PUCO could take. Management is unable
to predict the outcome of the PUCO's investigation or its impact on results of
operations and business practices, if any.
Virginia Restructuring - In Virginia, choice of electricity supplier for retail
customers began on January 1, 2002 under its restructuring law. Presently, APCo
continues to service all its previous customers under capped rates. A finding by
the Virginia SCC that an effective competitive market exists would be required
to end the transition period prior to its scheduled end on June 30, 2007.
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.
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.
In July 2002 APCo filed with the Virginia SCC requesting an increase in fuel
rates effective January 1, 2003. A public hearing was held on September 23, 2002
related to this filing. On November 8, 2002, a decision was issued in this
proceeding approving an annual increase of approximately $24 million.
The Virginia restructuring law also required filings to be made that outline the
functional separation of generation from transmission and distribution and a
rate unbundling plan. In January 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 did not and will not collect a wires charge in 2002 or 2003,
respectively. The settlement agreements and related Virginia SCC order addressed
functional separation leaving decisions related to corporate separation for
later consideration.
Texas Restructuring - In preparation for the start of competition in Texas, CPL,
SWEPCo, and WTU, the integrated electric utility companies operating in Texas,
were required to make PUCT filings and legal and operational changes to their
business. AEP formed new subsidiaries, Mutual Energy CPL L.P. and Mutual Energy
WTU L.P., to act as retail electric providers (REP) in Texas beginning on
January 1, 2002, the effective date of customer choice in Texas. The CPL and WTU
names continued to be used by the registrant subsidiaries which owned the
generation, transmission and distribution assets located in the ERCOT areas of
Texas and WTU's entire operations in SPP throughout most of 2002. In December
2002 WTU transferred its SPP retail customers to Mutual Energy SWEPCO L.P. AEP
sold the new subsidiaries that serve ERCOT retail customers to Centrica in
December 2002, along with the Central Power and Light and West Texas Utilities
brand names. CPL and WTU changed their names to AEP Texas Central Company (TCC)
and AEP Texas North Company (TNC), respectively.
On January 1, 2002, customer choice of electricity supplier began in the ERCOT
area of Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. All of SWEPCo's Texas service territory and a small
portion of TNC's service territory are located in the SPP. TCC operates entirely
in the ERCOT area of Texas.
Texas restructuring legislation, among other things:
o provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for an earnings test for each of the years 1999 through 2001 which
will reduce stranded cost recoveries or if there is no stranded cost
provides for a refund or their use to fund certain capital expenditures;
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
utility;
o provides for certain limits for ownership and control of generating
capacity by companies and;
o provides for a 2004 true-up proceeding to quantify and reconcile the
amount of stranded costs, final fuel balances, net regulatory assets,
certain environmental costs, accumulated excess earnings, excess of
price-to-beat revenues over market prices subject to certain conditions
and limitations (Retail clawback), and the difference between the price of
power obtained through the legislatively-mandated capacity auctions and
the power costs used in the PUCT's ECOM model for 2002 and 2003 (Wholesale
clawback) and other issues.
Under the Texas Legislation, electric utilities were required to submit a plan
to structurally unbundle business activities into a retail electric provider, a
power generation company and a transmission and distribution (T&D) utility. In
2000 SWEPCo, TCC and TNC filed their business separation plans with the PUCT.
The PUCT approved the plans for TCC and TNC but determined that competition in
the SPP areas of Texas should be delayed indefinitely and abated SWEPCo's plan.
Operations for TCC and TNC have been functionally separated consistent with the
approved plans. The delivery of electricity in ERCOT continues to be the
responsibility of TCC and TNC at regulated prices.
Texas Legislation provides electric utilities an opportunity to recover
regulatory assets and stranded costs resulting from the unbundling of the T&D
utility from the generation facilities. Stranded costs are the difference
between regulatory net book value of generation assets and the market value of
the assets based on one of several methodologies authorized by the Texas
Legislation. Stranded costs can be refinanced through securitization (a
financing structure designed to provide lower financing costs than are available
through conventional financings).
In 1999 TCC 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). TCC issued its securitization
bonds in February 2002. The annual cost of the bonds are recovered through a
PUCT approved transition charge in distribution rates.
TCC 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 Consolidated Balance Sheets. These STP costs had
previously been identified as excess cost over market (ECOM) by the PUCT for
regulatory purposes. They were 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 TCC's stranded costs was negative $615 million. TCC
disagreed with the ruling (see discussion of appeal ruling below). The ruling
indicated that TCC's costs were below market after securitization of regulatory
assets. The final amount of TCC's stranded costs including regulatory assets and
ECOM will be established by the PUCT in the 2004 true-up proceeding. If TCC'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 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, stock valuation or the use of an ECOM model.
TCC decided to obtain a market value of generating assets for purposes of
determining stranded costs for the 2004 true-up proceeding and filed a plan of
divestiture with the PUCT in December 2002 seeking approval of a sales process
for all of its generating facilities. Such sales quantify the actual stranded
costs. The amount of stranded costs under this market valuation methodology will
be the amount by which net book value of TCC's generating assets, including
regulatory assets and liabilities that were not securitized, exceeds the market
value of the generation assets as measured by the net proceeds from the sale of
the assets. It is anticipated that any such sale will result in significant
stranded costs for purposes of the 2004 true-up proceeding. The filing included
a request for the PUCT to issue a declaratory order that TCC's 25% ownership
interest in its nuclear plant, STP, can be sold to value stranded costs.
Intervenors to this proceeding, including the PUCT Staff, have made filings to
dismiss TCC's filing claiming that the PUCT does not have the authority to issue
a declaratory order. The intervenors also argued that the proper time to address
the sales process is after the plants are sold during the 2004 true-up
proceeding. Since the bidding process is not expected to be completed before mid
2004, TCC requested that the 2004 true-up proceeding be scheduled after
completion of the divestiture of the generating assets.
Texas Legislation also requires that electric utilities and their affiliated
power generation companies (PGC) sell at auction in 2002 and 2003 at least 15%
of the PGC's Texas jurisdictional installed generation capacity in order to
promote competitiveness in the wholesale market through increased availability
of generation and liquidity. Actual market power prices received in the state
mandated auctions will replace the PUCT's earlier estimates of those market
prices used in the ECOM model to calculate the stranded cost for the 2004
true-up proceeding.
The decision to determine stranded costs using market prices, instead of using
the PUCT's ECOM model estimates, enabled TCC to record a $262 million regulatory
asset and related revenues which represents the quantifiable amount of stranded
costs for the year 2002 related to the wholesale prices. Prior to the decision
to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited
the recognition of the regulatory assets and revenues as there was no way to
quantify stranded costs. As discussed above, a defined process is required in
order to determine the amount of stranded costs related to generation facilities
for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT
during December 2002 provided such a process.
When the divestiture and the 2004 true-up process are completed, TCC will
securitize any stranded costs which exceed current securitized amounts. The
annual costs of securitization will be recovered through a non-bypassable rate
surcharge by the regulated T&D utility over the life of the securitization
bonds. Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate non-bypassable
competitive transition charge to T&D utility customers.
The Texas Legislation provides for an earnings test each year 1999 through 2001
and requires PUCT approval of the annual earnings test calculation.
The PUCT issued final orders for the 1999 earnings test in February 2001 and for
the 2000 earnings test in September 2001. The 1999 excess earnings were none for
SWEPCo, $24 million for TCC and $1 million for TNC. Excess earnings for 2000
were $1 million for SWEPCo, $23 million for TCC and $17 million for TNC.
Adjustments were recorded in results of operations as the orders were received.
The PUCT issued its final order for the 2001 earnings test in December 2002. An
estimate of 2001 excess earnings of $8 million for TCC, $2 million for SWEPCo
and none for TNC had been recorded in 2001. Adjustments to reflect the PUCT
staff's estimate of excess earnings ($2 million for SWEPCo, $0.7 million for TNC
and none for TCC) were recorded prior to September 30, 2002. The PUCT's final
order regarding 2001 excess earnings required only minor adjustments to prior
estimates.
Due to TCC's and TNC's disagreement with the PUCT's final order for the 2000
excess earnings, the companies filed an appeal in district court in 2001 seeking
judicial review of the PUCT's determination of excess earnings. The district
court upheld the PUCT's order and the companies appealed that decision. A ruling
on the appeal is expected in 2003.
On January 28, 2003, the TCC and TNC filed an appeal in District Court seeking
judicial review of the PUCT order for the 2001 excess earnings.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would
be made to the amount of stranded costs authorized by the PUCT to be
securitized. Final stranded cost amounts and the treatment of excess earnings
will be determined in the 2004 true-up proceeding. To the extent that the final
2004 true-up proceeding determines that TCC should recover additional stranded
costs, the additional amount recoverable can also be securitized. The PUCT also
ruled that estimated excess earnings for the period 1999-2001 should be refunded
through distribution rates to the extent of any over-mitigation of stranded
costs represented by negative ECOM. In 2001 the PUCT issued an order requiring
TCC to reduce distribution rates by approximately $54.8 million plus accrued
interest over a five-year period beginning January 1, 2002 in order to return
estimated excess earnings for 1999, 2000 and 2001. Since excess earnings amounts
were expensed in 1999, 2000 and 2001, the order has no additional effect on
reported net income but will reduce cash flows for the five year refund period.
The amount to be refunded is recorded as a regulatory liability.
Management believes that TCC will have stranded costs in 2004. TCC has appealed
the PUCT's refund of excess earnings to the Travis County District Court and,
depending on the outcome of that appeal (and the final outcome of the rulemaking
challenge discussed below), the PUCT may revise the treatment of excess earnings
in the final calculation of the stranded cost balance. In the same appeal, TCC
and certain unaffiliated parties also challenged various elements of the PUCT's
order determining the estimated stranded costs of TCC, with the unaffiliated
parties contending, among other things, that the entire $615 million of negative
stranded costs should be refunded presently. Prior to the Court hearing on this
issue, however, TCC agreed to give up its claims concerning errors in the
calculation of the stranded cost estimate, while the unaffiliated parties agreed
to give up claims that there should be a refund of negative stranded costs. The
Travis County District Court subsequently heard oral arguments concerning the
remaining issues in the appeal, but has not yet issued a decision. The PUCT's
stranded cost estimate that is the subject of this appeal will be superceded by
a final determination of stranded costs to be accomplished as part of the 2004
true-up proceeding.
In a separate appeal challenging the PUCT's substantive rule governing the 2004
true-up proceeding, the Texas Third Court of Appeals ruled in February 2003,
that the Texas Legislation does not contemplate the refunding of negative
stranded costs to customers. The Court of Appeals held that the PUCT was
justified in using any negative stranded cost balance determined in the 2004
true-up proceeding only as an offset to prevent an over-recovery of stranded
costs via securitization. In addition, the Court of Appeals ruled that negative
stranded costs cannot be offset against other true-up balances, including final
under-recovered fuel amounts. This ruling may be further appealed to the Supreme
Court of Texas.
Beginning January 1, 2002, fuel costs are not subject to PUCT fuel
reconciliation proceedings for TCC and TNC's ERCOT retail customers. Due to the
delay of competition for SWEPCo's SPP area of Texas, SWEPCo continues to record
and request recovery of fuel costs subject to Texas fuel proceedings. Final
deferred fuel balances related to ERCOT customers of TCC and TNC at December 31,
2001 will be included in the 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.
Under the Texas Legislation, retail electric providers (REPs) associated with
integrated utilities are required 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 the
AEP REPs in TCC's and TNC's ERCOT area. Customers with a peak usage of more than
1000 KW are subject to market rates. The Texas Restructuring Legislation also
provides that a REP associated with integrated utilities may request an
adjustment of its fuel portion of the price-to-beat rate up to two times
annually to reflect changes in market prices of fuel and purchased energy costs
based upon changes in NYMEX gas prices.
As part of the 2004 true-up proceedings the price-to-beat rates charged by AEP
REPs for 2002 and 2003 will be compared to the market rates for the same period.
If market rates are lower, the excess of the price-to-beat, reduced by non-
bypassable delivery charges, over the prevailing market prices must be returned
to the distribution company, subject to a per customer maximum. During 2002, AEP
provided for such potential liabilities at the maximum amount via a charge to
revenues, and recorded a regulatory liability for TCC and TNC. These amounts
were $52 million for TCC and $14 million for TNC.
West Virginia Restructuring - 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.
A Joint Stipulation approved by the WVPSC in 2000 in connection with an APCo
base rate filing, allowed for recovery of regulatory assets including any
generation-related regulatory assets through the following provisions:
o Frozen transition rates and a wires charge of 0.5 mills per KWH.
o 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.
o The retention of net merger savings prior to December 31, 2004 resulting
from the merger of AEP and CSW.
o A 0.5 mills per KWH wires charge for departing customers provided for in
the WV Restructuring Plan.
Management expects that the approved Joint Stipulation provides for the recovery
of existing regulatory assets and other stranded costs.
In order for customer choice to become effective in WV, the WV Legislature
needed to enact additional legislation to preserve the revenues of state and
local government. In the subsequent two legislative sessions, which usually end
in March each year, the West Virginia Legislature has not enacted the required
legislation. Due to the lack of legislative activity, the WVPSC closed two
proceedings related to electricity restructuring in the summer of 2002.
The two closed proceedings related to the respective dockets intended originally
to determine whether West Virginia should deregulate the generation business,
and to develop the WVPSC's Deregulation Plan and related rules to implement the
Plan.
Management has reviewed these two proceedings and concluded that at this time it
is not clear that APCo meets the requirements to reapply SFAS 71. Management
will monitor developments to determine when it is appropriate to reapply SFAS 71
to APCo's generation business.
Arkansas Restructuring - In 1999 Arkansas enacted legislation to restructure its
electric utility industry.
In February 2003 the Arkansas General Assembly passed legislation that repealed
customer choice legislation, which is currently awaiting signature by the
Governor of Arkansas.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas,
Ohio, Texas, Virginia and West Virginia - The enactment of restructuring
legislation and the ability to determine transition rates, wires charges and any
resultant gain or loss under restructuring legislation in Arkansas, Ohio, Texas,
Virginia and West Virginia resulted in AEP and certain subsidiaries
discontinuing regulatory accounting under SFAS 71 for the generation portion of
their business in those states. Under the provisions of SFAS 71, regulatory
assets and regulatory liabilities are recorded to reflect the economic effects
of regulation by matching expenses with related regulated revenues.
The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas,
Virginia and West Virginia resulted in recognition of extraordinary gains or
losses. The discontinuance of SFAS 71 can require the write-off of regulatory
assets and liabilities related to the deregulated operations, unless their
recovery is provided through cost-based regulated rates to be collected in a
portion of operations which continues to be rate regulated. Additionally, a
company must determine if any plant assets are impaired when they discontinue
SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis
showed that there was no accounting impairment of generation assets.
As a result of deregulation of generation, the application of SFAS 71 for the
generation portion of the business in Arkansas, Ohio, Texas, Virginia and West
Virginia was discontinued. Remaining generation-related regulatory assets will
be amortized as they are recovered under terms of transition plans. Management
believes that substantially all generation-related regulatory assets and
stranded costs will be recovered under terms of the transition plans. If future
events including the 2004 true-up proceeding in Texas were to make their
recovery no longer probable, the companies would write-off the portion of such
regulatory assets and stranded costs deemed unrecoverable as a non-cash
extraordinary charge to earnings. If any write-off of regulatory assets or
stranded costs occurred, it could have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
Michigan Restructuring - 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. I&M's total rates in Michigan remain unchanged and reflect cost of
service. At December 31, 2002, none of I&M's customers have elected to change
suppliers and no alternative electric suppliers are registered to compete in
I&M's Michigan service territory.
Management has concluded that as of December 31, 2002 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.
9. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial construction
commitments to support its operations. Aggregate construction expenditures for
2003-2005 for consolidated domestic and foreign operations are estimated to be
$4.7 billion.
APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Certificates have been issued by both the West Virginia Public
Service Commission and the Virginia State Corporation Commission authorizing
construction and operation of the line. On December 31, 2002, the U.S. Forest
Service issued a final environmental impact statement and record of decision to
allow the use of federal lands in the Jefferson National Forest for construction
of a portion of the line. We expect additional state and federal permits to be
issued in the first half of 2003. Through December 31, 2002, we had invested
approximately $51 million in this effort. The line is estimated to cost $287
million including amounts spent to date with completion scheduled in 2006. If
the required permits are not obtained and the line is not constructed, the $51
million investment would be written off, adversely affecting future results of
operations and cash flows.
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 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 unit contingent contracts to supply approximately 250 MW of
capacity to unaffiliated entities through December 31, 2009. The commitment is
pursuant to a unit power agreement requiring the delivery of energy only if the
unit capacity is available.
Power Generation Facility - AEP has entered into agreements with Katco Funding
L.P. (Katco) an unrelated unconsolidated special purpose entity. Katco has an
aggregate financing commitment of $525 million and a capital structure of which
3% is equity from investors with no relationship to AEP or any of its
subsidiaries and 97% is debt from a syndicate of banks. Katco was formed to
develop, construct, finance and lease a power generation facility to AEP. Katco
will own the power generation facility and lease it to AEP after construction is
completed. The lease will be accounted for as an operating lease (see Note 22),
therefore neither the facility nor the related obligations are reported on AEP's
balance sheet. Payments under the operating lease are expected to commence in
the first quarter of 2004. AEP will in turn sublease the facility to Dow
Chemical Company (DOW), which will use the energy produced by the facility and
sell excess energy. AEP has agreed to purchase the excess energy from DOW for
resale. The use of Katco allows AEP to limit its risk associated with the power
generation facility once the construction phase has been completed.
AEP, is the construction agent for Katco, and is responsible for completing
construction by December 31, 2003, subject to unforeseen events beyond AEP's
control.
In the event the project is terminated before completion of construction, AEP
has the option to either purchase the facility for 100% of project costs or
terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation
date of the facility and continues until November 2006. The lease contains
extension options subject to the approval of Katco, and if all extension options
were exercised, the total term of the lease would be 30 years. AEP's lease
payments to Katco are sufficient for Katco to make required debt payments and
provide a return to the investors of Katco. At the end of each lease term, AEP
may renew the lease at fair market value subject to Katco's approval, purchase
the facility at its original construction cost, or sell the facility, on behalf
of Katco, to an independent third party. If the facility is sold and the
proceeds from the sale are insufficient to repay Katco, AEP may be required to
make a payment to Katco for the difference between the proceeds from the sale
and the obligations of Katco, up to 82% of the project's cost. AEP has
guaranteed a portion of the obligations of its subsidiaries to Katco during the
construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360
million, and total costs for the completed facility are expected to be
approximately $510 million. For the 30-year extended lease term, the lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently
as market interest rates increase, the payments under this operating lease will
also increase. Annual payments of approximately $12 million represent future
minimum payments during the initial term calculated using the indexed LIBOR rate
(1.38% at December 31, 2002). The Power Generation Facility collateralizes the
debt obligation of Katco. AEP's maximum exposure to loss as a result of its
involvement with Katco is 100% during the construction phase and up to 82% once
the construction is completed. Maximum loss is deemed to be remote due to the
collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter
of 2003, as a result of the issuance of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP
would record the assets, liabilities, depreciation expense, minority interest
and debt interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation. OPCo has entered
into a 30-year power purchase agreement for electricity produced by an
unaffiliated entity's three-unit natural gas fired plant. The plant was
completed in 2002 and the agreement will terminate in 2032. Under the terms of
the agreement, OPCo has the option to run the plant until December 31, 2005
taking 100% of the power generated and making monthly capacity payments. The
capacity payments are fixed through December 2005 at $1.2 million per month. For
the remainder of the 30-year contract term, OPCo will pay the variable costs to
generate the electricity it purchases (up to 20% of the plant's capacity).
Nuclear Plants - I&M owns and operates the two-unit 2,110 MW Cook Plant under
licenses granted by the NRC. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC
operates STP on behalf of the joint owners under licenses granted by the NRC.
The operation of a nuclear facility involves special 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 TCC 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 from customers is not possible, results of operations, cash flows
and financial condition would be adversely affected.
Nuclear Incident Liability - 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. TCC 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. Under an industry-wide program insuring workers at nuclear facilities,
I&M and TCC are also obligated for assessments of up to $6.2 million and $1.6
million, respectively, for potential claims. These obligations will remain in
effect until December 31, 2007.
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. I&M and STPNOC jointly purchase $1 billion of excess coverage for
property damage, decommissioning 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 TCC which
is assessable if the insurer's financial resources would be inadequate to pay
for losses.
The current Price-Anderson Act expired in August 2002. Its contingent financial
obligations still apply to reactors licensed by the NRC as of its expiration
date. It is anticipated that the Price-Anderson Act will be renewed with
increased third party financial protection requirements for nuclear incidents.
Spent Nuclear Fuel Disposal - 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 $224 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, 2002, funds collected from customers towards payment of the pre-April 1983
fee and related earnings thereon are in external funds and exceed the liability
amount. TCC 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 - 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 using
the prompt decontamination and dismantlement (DECON) method. 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
recovering estimated Cook Plant decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The amount
recovered in rates for decommissioning the Cook Plant and deposited in the
external fund was $27 million in 2002 and 2001 and $28 million in 2000.
The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
DECON method. TCC estimates its portion of the costs of decommissioning STP to
be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering
these decommissioning costs through rates based on the service life of STP at a
rate of $8 million per year.
Decommissioning costs recovered from customers are deposited in external trusts.
In 2002 and 2001 I&M deposited in its decommissioning trust an additional $12
million each year related to special regulatory commission approved funding for
decommissioning of the Cook Plant. Trust fund earnings increase the fund assets
and the recorded liability and decrease the amount needed to be recovered from
ratepayers. Decommissioning costs including interest, unrealized gains and
losses and expenses of the trust funds are recorded in other operation expense
for Cook Plant. For STP, nuclear decommissioning costs are recorded in other
operation expense, interest income of the trusts are recorded in nonoperating
income and interest expense of the trust funds are included in interest charges.
On the Consolidated Balance Sheets, nuclear decommissioning trust assets are
included in Other Assets and a corresponding nuclear decommissioning liability
is included in Other Noncurrent Liabilities. The decommissioning liability for
both nuclear plants combined totals $719 million and $699 million at December
31, 2002 and 2001, respectively.
Federal EPA Complaint and Notice of Violation -
Since 1999 AEP has been involved in litigation regarding generating plant
emissions under the Clean Air Act. Federal EPA and a number of states alleged
that AEP System companies and eleven unaffiliated utilities modified certain
units at coal fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against AEP subsidiaries in U.S. District 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 2001 the
District Court ruled claims for civil penalties based on activities that
occurred more than five years before the filing date of the complaints cannot be
imposed. There is no time limit on claims for injunctive relief.
Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense.
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 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 the 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 - 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.
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
imposed 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. In August 2001 the D.C. Circuit Court issued an order tolling
the compliance schedule until Federal EPA responded to the Court's remand. On
April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date
for the Section 126 Rule. Federal EPA published a notice in the Federal Register
in May 2002 advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and
industrial organizations in seeking a review of Federal EPA's action in the D.C.
Circuit Court. This action is pending.
In 2000 the Texas Commission on Environmental Quality (formerly the Texas
Natural Resource Conservation Commission) adopted rules requiring significant
reductions in NOx emissions from utility sources, including SWEPCo and TCC. The
compliance date is May 2003 for TCC and May 2005 for SWEPCo.
AEP is installing a variety of emission control technologies to reduce NOx
emissions to comply with the applicable state and Federal NOx requirements. This
includes selective catalytic reduction (SCR) technology on certain units and
non-SCR technologies on a larger number of units. During 2001 SCR technology
commenced operations on OPCo's Gavin Plant. Installation of SCR technology on
Amos and Mountaineer plants was completed and commenced operation in May 2002.
Construction of SCR technology at certain other AEP generating units continues.
Non-SCR technologies have been installed and commenced operation on a number of
units across the AEP System and additional units will be equipped with these
technologies.
The AEP NOx compliance plan is a dynamic plan that is continually reviewed and
revised as new information becomes available on the performance of installed
technologies and the cost of planned technologies. Certain compliance steps may
or may not be necessary as a result of this new information. Consequently, the
plan has a range of possible outcomes. Our current estimates indicate that
compliance with the NOx Rule, the Texas Commission on Environmental Quality rule
and the Section 126 Rule could result in required capital expenditures in the
range of $1.3 billion to $2 billion of which $843 million has been spent through
December 31, 2002. The range of cost estimates reflects the uncertainty over the
need for certain SCR projects.
Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the estimates depending upon the
compliance alternatives selected to achieve reductions in NOx emissions. Unless
any capital and operating costs of additional pollution control equipment are
recovered from customers, they will have an adverse effect on results of
operations, cash flows and possibly financial condition.
Merger Litigation - On January 18, 2002, the U.S. Court of Appeals for the
District of Columbia ruled that the SEC did not properly find that the June 15,
2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the
case back to the SEC for further review. Specifically, the court required the
SEC to revisit and identify factors supporting its conclusion that the merger
met PUHCA requirements that utilities be "physically interconnected" and
confined to a "single area or region."
In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUCHA's single
region requirement because it is now technically possible to centrally control
the output of power plants across many states. In its ruling, the appeals court
said that the SEC failed to support and explain its conclusions that the
integration and single region requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA and
expects the matter to be resolved favorably.
Enron Bankruptcy - On October 15, 2002, certain subsidiaries of AEP filed claims
against Enron and its subsidiaries in the bankruptcy proceeding filed by the
Enron entities which are pending in the U.S. Bankruptcy Court for the Southern
District of New York. 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 Company (HPL) from Enron.
Various HPL related contingencies and indemnities remained unsettled at the date
of Enron's bankruptcy. The timing of the resolution of the claims by the
Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive rights to
use and operate the underground Bammel gas storage facility pursuant to an
agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This
exclusive right to use the referenced facility is for a term of 30 years, with a
renewal right for another 20 years and includes the use of the Bammel storage
reservoir and the related compression, treating and delivery systems. We have
engaged in preliminary discussions with Enron concerning the possible purchase
of the residual interest held by Enron in the Bammel storage facility and the
possible resolution of outstanding issues between AEP and Enron relating to our
acquisition of its interest in the Bammel storage facility. We are unable to
predict whether these discussions will lead to an agreement on these subjects.
If these discussions do not lead to an agreement, there may be a dispute with
Enron concerning our ability to continue utilization of the Bammel storage
facility under the existing agreement.
We also entered into an agreement with BAM Lease Company which grants HPL the
right to use approximately 65 billion cubic feet of cushion gas (or pad gas)
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust, which purportedly owned approximately 55 billion cubic feet of the
gas, had entered into a financing arrangement in 1997 with Enron and a group of
banks. These banks purported to have certain rights to the gas in certain events
of default. In connection with AEP's acquisition of HPL, the banks entered into
an agreement granting HPL's use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was thereafter
informed by the banks of a purported default by Enron under the terms of the
referenced financing arrangement. In July 2002 the banks filed a lawsuit against
HPL seeking a declaratory judgment that they have a valid and enforceable
security interest in this cushion gas which would permit them to cause the
withdrawal of this gas from the storage facility. In September 2002 HPL filed a
general denial and certain counterclaims against the banks. Management is unable
to predict the outcome of this lawsuit or its impact on results of operations
and cash flows.
In 2001 AEP expensed $47 million ($31 million net of tax) for our estimated loss
from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a
cumulative loss of $53 million ($34 million net of tax). The amounts expensed
were based on an analysis of contracts where AEP and Enron entities are
counterparties, the offsetting of receivables and payables, the application of
deposits from Enron entities and management's analysis of the HPL related
purchase contingencies and indemnifications.
Enron has recently instituted proceedings against other energy trading
counter-parties challenging the practice of utilizing offsetting receivables and
payables and related collateral across various Enron entities. We believe that
we have the right to utilize similar procedures in dealing with payables,
receivables and collateral with Enron entities by offsetting approximately $110
million of trading payables owed to various Enron entities against trading
receivables due to us. We believe we have legal defenses to any challenge that
may be made to the utilization of such offsets but at this time are unable to
predict the ultimate resolution of this issue.
Shareholder Lawsuits - In the fourth quarter of 2002 lawsuits alleging
securities law violations and seeking class action certification were filed in
federal District Court, Columbus, Ohio against AEP, certain AEP executives, and
in some of the lawsuits, members of the AEP Board of Directors and certain
investment banking firms. The lawsuits claim that AEP failed to disclose that
alleged "round trip" trades resulted in an overstatement of revenues, that AEP
failed to disclose that AEP traders falsely reported energy prices to trade
publications that published gas price indices and that AEP failed to disclose
that it did not have in place sufficient management controls to prevent round
trip trades or false reporting of energy prices. The plaintiffs seek recovery of
an unstated amount of compensatory damages, attorney fees and costs. The cases
are presently pending a decision by the Court on competing motions by certain
plaintiffs and groups of plaintiffs' for designation as lead plaintiff. Once the
Court selects a lead plaintiff, that lead plaintiff will file an amended
complaint. AEP intends to vigorously defend against these actions. Also in the
fourth quarter of 2002, two shareholder derivative actions were filed in state
court in Columbus, Ohio against AEP and its Board of Directors alleging a breach
of fiduciary duty for failure to establish and maintain adequate internal
controls over AEP's gas trading operations; and, a lawsuit was filed against
AEP, certain AEP executives and AEP's ERISA Plan Administrator in federal
District Court for the Southern District of New York (subsequently transferred
to federal District Court in Columbus, Ohio) alleging violations of the Employee
Retirement Income Security Act in the selection of AEP stock as a investment
alternative and in the allocation of assets to AEP stock. These cases are in the
initial pleading stage. AEP intends to vigorously defend against these actions.
California Lawsuit - In November 2002 Cruz Bustamante, Lieutenant Governor of
California, filed a lawsuit in Los Angeles County, California Superior Court
against forty energy companies including AEP and two publishing companies
alleging violations of California law through alleged fraudulent reporting of
false natural gas price and volume information with an intent to affect the
market price of natural gas and electricity. This case is in the initial
pleading stage. AEP intends to vigorously defend against this action.
Arbitration of Williams Claim - In October 2002 AEP filed its demand for
arbitration with the American Arbitration Association to initiate formal
arbitration proceedings in a dispute with the Williams Companies (Williams). The
proceeding results from Williams' repudiation of its obligations to provide
physical power deliveries to AEP and Williams' failure to provide the monetary
security required for natural gas deliveries by AEP. Consequently, both parties
claimed default and terminated all outstanding natural gas and electric power
trading deals among the various Williams and AEP affiliates. Williams claimed
that AEP owes approximately $130 million in connection with the termination and
liquidation of all trading deals. AEP believes it has valid claims arising from
Williams' actions and is seeking, in part, a determination that either no amount
is due or that a lesser amount is due from AEP to Williams (which is fully
reserved by AEP) and the extent of any other damages and legal or equitable
relief available. Although management is unable to predict the outcome of this
matter, it is not expected to have a material impact on results of operations,
cash flows or financial condition.
Energy Market Investigations - In February 2002 the FERC issued an order
directing its Staff to conduct a fact-finding investigation into whether any
entity, including Enron, manipulated short-term prices in electric energy or
natural gas markets in the West or otherwise exercised undue influence over
wholesale prices in the West, for the period January 1, 2000, forward. In April
2002 AEP furnished certain information to the FERC in response to their related
data request.
Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further
data requests, including requests for admissions, with respect to certain
trading strategies engaged in by Enron and, allegedly, traders of other
companies active in the wholesale electricity and ancillary services markets in
the West, particularly California, during the years 2000 and 2001. This data
request was issued to AEP as part of a group of over 100 entities designated by
the FERC as all sellers of wholesale electricity and/or ancillary services to
the California Independent System Operator and/or the California Power Exchange.
The May 8, 2002 FERC data request required senior management to conduct an
investigation into our trading activities during 2000 and 2001 and to provide an
affidavit as to whether we engaged in certain trading practices that the FERC
characterized in the data request as being potentially manipulative. Senior
management complied with the order and denied our involvement with those trading
practices.
On May 21, 2002, the FERC issued a further data request with respect to this
matter to us and over 100 other market participants requesting information for
the years 2000 and 2001 concerning "wash," "round trip" or "sale/buy back"
trading in the Western System Coordinating Council (WSCC), which involves the
sale of an electricity product to another company together with a simultaneous
purchase of the same product at the same price (collectively, "wash sales").
Similarly, on May 22, 2002, the FERC issued an additional data request with
respect to this matter to us and other market participants requesting similar
information for the same period with respect to the sale of natural gas products
in the WSCC and Texas. After reviewing our records, we responded to the FERC
that we did not participate in any "wash sale" transactions involving power or
gas in the relevant market. We further informed the FERC that certain of our
traders did engage in trades on the Intercontinental Exchange, an electronic
electricity trading platform owned by a group of electricity trading companies,
including us, on September 21, 2001, the day on which all brokerage commissions
for trades on that exchange were donated to charities for the victims of the
September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a
"wash sale" but do have certain characteristics in common with such sales. In
response to a request from the California attorney general for a copy of AEP's
responses to the FERC inquires, we provided the pertinent information.
The PUCT also issued similar data requests to AEP and other power marketers. AEP
responded to such data requests by the July 2, 2002 response date. The U.S.
Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17,
2002 requesting information with respect to "wash sale" trading practices. We
responded to CFTC. In addition, the U.S. Department of Justice made a civil
investigation demand to us and other electric generating companies concerning
their investigation of the Intercontinental Exchange. We have completed a review
of our trading activities in the United States for the last three years
involving sequential trades with the same terms and counterparties. The revenue
from such trading is not material to our financial statements. We believe that
substantially all these transactions involve economic substance and risk
transference and do not constitute "wash sales".
In August 2002 we received an informal data request from the SEC asking us to
voluntarily provide documents related to "round trip" or "wash" trades. We have
provided the requested information to the SEC.
In September 2002 we received a subpoena from FERC requesting information about
our natural gas transactions and their potential impact on gas commodity prices
in the New York City area. We responded to the subpoena in October 2002.
In October 2002 AEP dismissed several employees involved in natural gas
marketing and trading after the Company determined that they provided inaccurate
price information for use in indexes compiled and published by trade
publications. AEP, subsequently, instituted measures that require all price
information for use in market indexes be verified and reported through AEP's
Chief Risk Officer's organization. We have and will continue to provide to the
FERC, the SEC and the CFTC information relating to price data given to energy
industry publications.
FERC Proposed Standard Market Design - In July 2002, the FERC issued its
Standard Market Design (SMD) notice of proposed rulemaking, one of the most
sweeping rulemaking proposals in its history. The proposed SMD rule seeks to
standardize the structure and operation of wholesale electricity markets across
the country. Key elements of FERC's proposal include standard rules and
processes for all users of the electricity transmission grid, new transmission
rules and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC recently
indicated that it would issue a white paper on the proposal in April 2003, in
response to the numerous comments by FERC received on its proposal. The FERC is
expected to issue its final rule in mid to late 2003. Because the rule is not
yet finalized, management cannot predict the effect of the final rule on cash
flows and results of operations.
FERC Proposed Security Standards - The FERC published for comment its proposed
security standards as part of the SMD. These standards are intended to ensure
all market participants have a basic security program that effectively protects
the electric grid and related market activities. They require compliance by
January 1, 2004. The impact of these proposed standards is far-reaching and
includes significant penalties for non-compliance. These standards apply to
market operations and transmission owners. For the AEP System this includes:
power generation plants, transmission systems, distribution systems and related
areas of business. FERC is considering new proposals to modify the scope and
timetable for compliance with the standards. Unless FERC changes the scope and
timing of the original proposed standards, those standards could result in
significant expenditures and operational changes in a compressed time frame, and
may adversely affect our results of operations and cash flows if such costs are
not recovered from customers.
FERC Market Power Mitigation - A FERC order issued in November 2001 on AEP's
triennial market based wholesale power rate authorization update required
certain mitigation actions that AEP would need to take for sales/purchases
within its control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for rehearing
filed by AEP and other market participants, FERC issued an order delaying the
effective date of the mitigation plan until after a planned technical conference
on market power determination. No such conference has been held and management
is unable to predict the timing of any further action by the FERC or its affect
on future results of operations and cash flows.
Other - We are involved in a number of other legal proceedings and claims. While
management is unable to predict the ultimate outcome of these matters, it is not
expected that their resolution will have a material adverse effect on results of
operations, cash flows or financial condition.
10. Guarantees
In November 2002 the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to
recognize a liability related to issuing a guarantee, as well as additional
disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57,
and 107 and a rescission of FIN 34. The initial recognition and initial
measurement provisions of FIN 45 is effective on a prospective basis to
guarantees issued or modified after December 31, 2002. The disclosure
requirements of FIN 45 are effective for financial statements of interim or
annual periods ending after December 15, 2002.
There are no liabilities recorded for all of the guarantees described below in
accordance with FIN 45 as these guarantees were entered into prior to December
31, 2002. There is no collateral held in relation to these guarantees and there
is no recourse to third parties in the event these guarantees are drawn.
Certain AEP subsidiaries have entered into standby letters of credit (LOC) with
third parties. These LOCs cover gas and electricity trading contracts,
construction contracts, insurance programs, security deposits, debt service
reserves, drilling funds and credit enhancements for issued bonds. All of these
LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary
course of business. TCC issued one of the LOCs for credit enhancement of issued
bonds. The maximum future payments of all the LOCs are approximately $166
million with maturities ranging from January 2003 to December 2007. Since AEP is
the parent to all these subsidiaries, it holds all assets of the subsidiary as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.
The following AEP subsidiaries have entered into guarantees of third party
obligations:
CSW Energy and CSW International have guaranteed 50% of the required debt
service reserve of Sweeny Cogeneration, an IPP of which CSW Energy is a 50%
owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as
a part of financing. In the event that Sweeny does not make the required debt
payments, CSW Energy and CSW International have a maximum future payment
exposure of approximately $3.7 million, which expires June 2020.
Additionally, CSW guaranteed 50% of the required debt service reserve for Polk
Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk
Power does not make the required debt payments, CSW has a maximum future payment
exposure of approximately $4.7 million, which expires July 2010.
In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to
assume the revolving credit agreement, capital lease obligations, and term loan
payments of the mining contractor. In the event the mining contractor defaults
under any of these agreements, SWEPCo's total future maximum payment exposure is
approximately $74 million with maturity dates ranging from April 2003 to
February 2012.
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 approximately $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, 2002 the cost to reclaim the mine is estimated to
be approximately $36 million. This guarantee ends upon depletion of reserves
estimated at 2035 plus 6 years to complete reclamation.
In connection with the ability for Mutual Energy CPL L.P. (former subsidiary of
AEP sold to Centrica on December 23, 2002) to compete in the CPL territory and
to secure transition charges, AEP provided a guarantee that AEP would pay
transition charges if Mutual Energy CPL failed to meet certain obligations. At
the time of sale this guarantee (matures in February 2003) was not revoked. The
future maximum payment exposure is $12.2 million. In February 2003, the
guarantee matured and no payments under the guarantee were required.
In connection with the ERCOT transmission congestion auction, AEP has guaranteed
the obligations of Mutual Energy CPL L.P. (former subsidiary of AEP sold to
Centrica on December 23, 2002) and Mutual Energy WTU L.P. (former subsidiary of
AEP sold to Centrica on December 23, 2002). At the time of sale these guarantees
were not revoked. The total future maximum payment exposure for both companies
is approximately $0.6 million. In January 2003 these guarantees matured and no
payments under the guarantees were required.
See Note 26 "Minority Interest in Finance Subsidiary" for disclosure of the
guaranteed support of AEP for Caddis Partners, LLC.
AEP and all its registrant and non-registrant subsidiaries enter into several
types of contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease agreements,
purchase agreements and financing agreements. Generally these agreements may
include, but are not limited to, indemnifications around certain tax,
contractual and environmental matters. At this time AEP cannot estimate the
maximum potential payment for any of these indemnifications due to the
uncertainty of future events. In addition, as of December 31, 2002, there are no
liabilities required for any indemnifications.
AEP and its regulated and non-regulated subsidiaries lease certain equipment
under a master operating lease. Under the lease agreement, the lessor is
guaranteed to receive up to 87% of the unamortized balance of the equipment at
the end of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have committed to
pay the difference between the fair market value and the unamortized balance,
with the total guarantee not to exceed 87% of the unamortized balance. At
December 31, 2002, the maximum potential loss for these lease agreements was
approximately $50 million assuming the fair market value of the equipment is
zero at the end of the lease term.
11. Sustained Earnings Improvement Initiative:
In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth.
Termination benefits expense relating to 1,120 terminated employees totaling
$75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this
amount, AEP paid $9.5 million to 312 terminated employees and recorded a
provision for $65.9 million related to 808 terminated employees. The payments
and accruals were classified as Maintenance and Other Operation expense on the
Consolidated Statements of Operations. We determined that the termination of the
employees under our SEI initiative did not constitute a curtailment under the
provisions of SFAS No. 88 "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits". In
addition, certain buildings and corporate aircraft are being sold in an effort
to reduce ongoing operating expenses.
12. Acquisitions, Dispositions and Discontinued Operations:
Acquisitions
SFAS 141 "Business Combinations" applies to all business combinations initiated
and consummated after June 30, 2001.
2002
Acquisition of Nordic Trading
In January 2002 AEP acquired for $2.2 million and other assumed liabilities the
trading operations, including key staff, of Enron's Norway and Sweden-based
energy trading businesses (Nordic Trading). Results of operations are included
in AEP's Consolidated Statements of Operations from the date of acquisition. The
excess of cost over fair value of the net assets acquired was approximately $4.0
million which was recorded as Goodwill. Subsequently in the fourth quarter of
2002, a decision was made to exit the non-core trading business in Europe and to
close or sell Nordic Trading as discussed under the "Discontinued Operations"
section of this note.
Acquisition of USTI
In January 2002 AEP acquired 100% of the stock of United Sciences Testing, Inc.
(USTI) for $12.5 million. USTI provides equipment and services related to
automated emission monitoring of combustion gases to both AEP affiliates and
external customers. Results of operations are included in AEP's Consolidated
Statements of Operations from the date of acquisition.
2001
On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe
Line Company and Lodisco LLC for $727 million from Enron. The acquired assets
include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a
gas storage facility and certain gas marketing contracts. The purchase method of
accounting was used to record the acquisition. According to APB Opinion No. 16
"Business Combinations" AEP recorded the assets acquired and liabilities assumed
at their estimated fair values determined by independent appraisal or by
Company's management based on information currently available and on current
assumptions as to future operations. Based on a final purchase price allocation
the excess of cost over fair value of the net assets acquired was approximately
$153 million and is recorded as Goodwill. SFAS 142 "Goodwill and Other
Intangible Assets" treats goodwill as a non-amortized, non-wasting asset
effective January 1, 2002. Therefore, Goodwill was amortized for only seven
months in 2001 on a straight-line basis over 30 years. The purchase method
results in the assets, liabilities and earnings of the acquired operations being
included in AEP's consolidated financial statements from the purchase date.
AEP also purchased the following assets or acquired the following businesses
from July 1, 2001 through December 31, 2001 for an aggregate total of $1,651
million:
o SWEPCo, an AEP subsidiary, purchased the Dolet Hills mining
operations and assumed the existing mine reclamation
liabilities at its jointly owned lignite reserves in Louisiana.
o Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP
also assumed additional liabilities of approximately $58 million. The
acquisition includes property, coal reserves, mining operations and
royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West
Virginia. AEP continues to operate the mines and facilities which
employ over 800 individuals. See Note 13b "Asset Impairments and
Investment Value Losses".
o MEMCO Barge Line added 1,200 hopper barges and 30 towboats to AEP's
existing barging fleet. MEMCO's 450 employees operate the barge line.
MEMCO added major barging operations on the Mississippi and Ohio rivers
to AEP's barging operations on the Ohio and Kanawha rivers.
o U.K. Generation added 4,000 megawatts of coal-fired generation from
Fiddler's Ferry, a four-unit, 2,000-megawatt station on the River
Mersey in northwest England, approximately 200 miles from London and
Ferrybridge, a four-unit, 2,000-megawatt station on the River Aire in
northeast England, approximately 200 miles from London and related coal
stocks. See Note 13b "Asset Impairments and Investment Value Losses".
o A 20% equity interest in Caiua, a Brazilian electric operating company
which is a subsidiary of Vale. See Note 21, "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. See Note 13b "Asset Impairments and Investment Value Losses".
o Indian Mesa Wind Project consisting of 160 megawatts of wind
generation located near Fort Stockton, Texas.
o Acquired existing contracts and hired key staff from Enron's
London-based international coal trading group.
Regarding the 2002 and 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.
Dispositions
2002
In 2002, AEP completed a number of disposals of assets determined to be
non-core:
Disposal of SEEBOARD
On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an
agreement, subject to European Union (EU) approval, to sell its consolidated
subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU
approval was received July 25, 2002 and the sale was completed on July 29, 2002.
AEP received approximately $941 million in net cash from the sale, subject to a
working capital true up, and the buyer assumed SEEBOARD debt of approximately
$1.12 billion, resulting in a net loss of $345 million at June 30, 2002. In
accordance with SFAS 144 the results of operations of SEEBOARD have been
classified as Discontinued Operations for all years presented. A net loss of $22
million was classified as Discontinued Operations in the second quarter of 2002.
The remaining $323 million of the net loss has been classified as a transitional
impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and has been
reported as a Cumulative Effect of Accounting Change retroactive to January 1,
2002. A $59 million reduction of the net loss was recognized in the second half
of 2002 to reflect changes in exchange rates to closing, settlement of working
capital true-up and selling expenses. The net total loss recognized on the
disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were
used to pay down bank facilities and short-term debt.
The assets and liabilities of SEEBOARD were aggregated on AEP's Consolidated
Balance Sheets as Assets of Discontinued Operations and Liabilities of
Discontinued Operations as of December 31, 2001. The major classes of SEEBOARD's
assets and liabilities of discontinued operations were:
December 31,
2001
(in millions)
Assets:
Current Assets $ 324
Plant,Property and Equipment, Net 1,283
Goodwill 1,129
Other Assets 96
------
Total Assets of Discontinued
Operations $2,832
Liabilities:
Current Liabilities $ 752
Long-term Debt 701
Deferred Income
Taxes 268
Other Liabilities 77
------
Total Liabilities of Discontinued
Operations $1,798
Disposal of CitiPower
On July 19, 2002, AEP, through a wholly owned subsidiary entered into an
agreement to sell Citipower, a retail electricity and gas supply and
distribution subsidiary in Australia. AEP completed the sale on August 30, 2002
and received net cash of approximately $175 million and the buyer assumed
CitiPower debt of approximately $674 million. AEP recorded a net charge totaling
$125 million as of June 30, 2002. The charge included an impairment loss of $98
million on the remaining carrying value of an intangible asset related to a
distribution license for CitiPower. The remaining $27 million of net loss was
classified as a transitional goodwill impairment loss from the adoption of SFAS
142 (see Notes 2 and 3) and was recorded as a cumulative effect of a change in
accounting principle retroactive to January 1, 2002.
The loss on the sale of CitiPower increased $24 million to $149 million in the
second half of 2002 based on actual closing amounts and exchange rates.
CitiPower's results of operations have been reclassified as Discontinued
Operations in accordance with SFAS 144. The assets and liabilities of Citipower
have been aggregated on the December 31, 2001, balance sheet as Assets of
Discontinued Operations and Liabilities of Discontinued Operations. The major
classes of CitiPower's assets and liabilities of discontinued operations are:
December 31,
2001
(in millions)
Assets:
Current Assets $ 138
Plant, Property and Equipment, Net 495
Goodwill/Intangibles 466
Other Assets 23
------
Total Assets of Discontinued
Operations $1,122
Liabilities:
Current Liabilities $ 83
Long-term Debt 612
Deferred Income Taxes 55
Other Liabilities 34
----
Total Liabilities of Discontinued
Operations
$784
Total revenues and pretax profit (loss) of the discontinued operations of
SEEBOARD and CitiPower were:
SEEBOARD
(in millions)
Revenues:
12 months ended
12/31/02 $ 694
12 months ended
12/31/01 1,451
12 month ended
12/31/00 1,596
Pretax Profit:
12 months ended
12/31/02 $ 180
12 months ended
12/31/01 104
12 months ended
12/31/00 91
CitiPower
(in millions)
Revenues:
12 months ended
12/31/02 $ 204
12 months ended
12/31/01 350
12 months ended
12/31/00 338
Pretax Profit:
12 months ended
12/31/02 $ (190)
12 months ended
12/31/01 (4)
12 months ended
12/31/00 20
Disposition of Texas REPs
In April 2002 AEP reached a definitive agreement, subject to regulatory
approval, to sell two of its Texas retail electric providers (REPs) to Centrica,
a provider of retail energy and other consumer services. PUCT regulatory
approval for the sale was obtained in December 2002. On December 23, 2002 AEP
sold to Centrica, the general partner interests and the limited partner
interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a base
purchase price paid in cash at closing and certain additional payments,
including a net working capital payment. Centrica paid a base purchase price of
$145.5 million which was based on a fair market value per customer established
by an independent appraiser and an agreed customer count. AEP recorded a net
gain totaling $83.7 million in Other Income. AEP will provide Centrica with a
power supply contract for the two REPs and back-office services related to these
customers for a two-year period. In addition, AEP retained the right to share in
earnings from the two REPs above a threshold amount through 2006 in the event
the Texas retail market develops increased earnings opportunities. Under the
Texas Legislation, REPs are subject to a clawback liability if customer change
does not attain thresholds required by the legislation. AEP is responsible for a
portion of such liability, if any, for the period it operated the REPs in the
Texas competitive retail market (January 1, 2002 through December 23, 2002). In
addition, AEP retained responsibility for regulatory obligations arising out of
operations before closing. AEP's wholly-owned subsidiary Mutual Energy Service
Company LLC (MESC) received an up-front payment of approximately $30 million
from Centrica associated with the back-office service agreement, and MESC
deferred its right to receive payment of an additional amount of approximately
$9 million to secure certain contingent obligations. These prepaid service
revenues were deferred on the books of MESC to be amortized over the two-year
term of the back office service agreement.
2001
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, resulting in an after tax gain of approximately $7 million. During 2002,
due to decreasing market value of the shares, we have reduced the value of them
to zero.
2000
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 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 writedown is included in Other
Income on AEP's Consolidated Statements of Operations. 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 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 Accumulated Other Comprehensive Income. In the
second quarter of 2000 management 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).
Discontinued Operations
The operations shown below were discontinued or classified as held for sale in
2002. Results of operations of these businesses have been reclassified as shown
in the following table.
SEEBOARD CitiPower Pushan Eastex Total
(in millions)
--------------------------
2002 Revenue $ 694 $204 $57 $ 73 $1,028
2001 Revenue 1,451 350 57 - 1,858
2000 Revenue 1,596 338 57 - 1,991
2002 Earnings
(Loss) After Tax 96 (123) (7) (156) (190)
2001 Earnings
(Loss) After Tax 88 (6) 4 - 86
2000 Earnings
(Loss) After Tax 99 17 7 (1) 122
-------------------------- ------------- ------------- -------------- ------------- -------------
13. Asset Impairments and Investment Value Losses:
In 2002 AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.426 billion (consisting of approximately $866.6 million
related to asset impairments, $321.1 million related to Investment Value and
Other Impairment Losses, and $238.7 million related to Discontinued Operations)
that reflected downturns in energy trading markets, projected long-term
decreases in electricity prices, and other factors. These impairments exclude
the transitional impairment loss from adoption of SFAS142 (see Notes 2 and 3).
The categories of impairments included:
--------------------------------- -----------------------------------
2002 Pre-Tax Estimated Loss
(in millions)
--------------------------------- -----------------------------------
Asset Impairments Held for Sale $ 483.1
Asset Impairments Held and Used 651.4
Investment Value Losses 291.9
--------------------------------- -----------------------------------
Total $1,426.4
--------------------------------- -----------------------------------
a. Assets Held for Sale
In 2002, AEP recorded the following estimated loss on disposal of assets
(including Goodwill) held for sale:
------------------------------ --------------------- ---------------------
2002 Pre-Tax
Estimated Loss
Assets on Disposal Business
Held for Sale (in millions)
------------------------------ --------------------- ---------------------
------------------------------ --------------------- ---------------------
Eastex $218.7 Wholesale
Pushan Power 20.0 Other
------------------------------ --------------------- ---------------------
------------------------------ --------------------- ---------------------
Total Impairment Losses
Included in Discontinued
Operations $238.7
------------------------------ --------------------- ---------------------
------------------------------ --------------------- ---------------------
Telecommunication - AEPC/C3 $158.5 Other
Newgulf Facility 11.8 Wholesale
Nordic Trading 5.3 Wholesale
Excess Equipment 23.9 Wholesale
Excess Real Estate 15.7 Wholesale
------------------------------ --------------------- ---------------------
------------------------------ --------------------- ---------------------
Total Included in
Asset Impairment Losses $215.2
------------------------------ --------------------- ---------------------
Telecommunications - AFN $ 13.8 Other
Water Heater Program 3.2 Wholesale
Gas Power Systems 12.2 Wholesale
------------------------------ --------------------- ---------------------
------------------------------ --------------------- ---------------------
Total Included in
Investment Value
and Other Impairment Losses $29.2
------------------------------ --------------------- ---------------------
------------------------------ --------------------- ---------------------
Total-All Held for Sale
Losses $483.1
------------------------------ ---------------------
Eastex
In 1998, CSW began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, AEP requested that the FERC allow it to modify the
FERC Merger Order and substitute Eastex as a required divestiture under the
order, due to the fact that the agreed upon market-power related divestiture of
a plant in Oklahoma was no longer feasible. The FERC approved the request at the
end of September 2002. Subsequently, in the fourth quarter of 2002 AEP solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. A sale of assets is expected to be completed by the end of 2003
with an estimated pre-tax loss on sale of $218.7 million included in
Discontinued Operations in the Consolidated Statements of Operations. The
estimated loss was based on the estimated fair value of the facility and
indicative bids by interested buyers.
Results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144 as shown in Note 12. The assets and
liabilities of Eastex have been included on AEP's Consolidated Balance Sheets as
held for sale. The major classes of assets and liabilities held for sale are:
2002 2001
(in millions)
Assets:
Current Assets $15 $ -
Property, Plant and Equipment, Net - 217
Other Assets - 3
--- ------
Total Assets Held for Sale $15 $220
=== ====
Liabilities:
Current Liabilities $ 8 $ 5
Other Liabilities 4 1
----- ------
Total Liabilities Held for Sale $12 $ 6
=== ======
Pushan Power Plant
In the fourth quarter of 2002, AEP began active negotiations to sell its
interest in the Pushan Power Plant (Pushan) in Nanyang, China to the minority
interest partner. Negotiations are expected to be completed by the second
quarter of 2003 with an estimated pre-tax loss on disposal of $20.0 million,
based on an indicative price expression. The estimated pre-tax loss on disposal
is classified in Discontinued Operations in the Consolidated Statements of
Operations.
Results of operations of Pushan have been reclassified as Discontinued
Operations in accordance with SFAS 144 as discussed in Note 12. The assets and
liabilities of Pushan have been classified on AEP's Consolidated Balance Sheets
as held for sale. The major classes of assets and liabilities held for sale are:
2002 2001
(in millions)
Assets:
Current Assets $ 19 $ 17
Property, Plant and Equipment, Net 132 161
----- -----
Total Assets Held for Sale $151 $178
==== ====
Liabilities:
Current Liabilities $ 28 $ 27
Long-term Debt 25 30
Other Liabilities 26 24
------ -----
Total Liabilities Held for Sale $ 79 $ 81
===== =====
Telecommunications
AEP had developed businesses to provide telecommunication services to businesses
and to other telecommunication companies through broadband fiber optic networks
operated in conjunction with AEP's electric transmission and distribution lines.
The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the
difficult economic conditions in these businesses and the overall
telecommunications industry, and other operating problems, the AEP Board
approved in December 2002 a plan to cease operations of these businesses. AEP
took steps to market the assets of the businesses to potential interested buyers
in the fourth quarter of 2002. A number of potential buyers have made offers for
the assets of C3. Potential buyers have indicated interest in the assets of AFN.
A formal offering of the assets of AEPC will begin early in 2003. The complete
sale of all telecommunication assets is expected to be completed by the end of
2003 with an estimated pre-tax impairment loss of $158.5 million (related to
AEPC and C3) classified in Asset Impairments in the Consolidated Statements of
Operations and an estimated pre-tax loss in value of the investment in AFN of
$13.8 million classified in Investment Value and Other Impairment Losses in the
Consolidated Statement of Operations. The estimated losses are based on
indicative bids by potential buyers.
$6 million and $182 million of Property, Plant and Equipment, net of accumulated
depreciation of the telecommunication businesses have been classified on AEP's
Consolidated Balance Sheets as held for sale in 2002 and 2001, respectively.
Newgulf Facility
In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002 AEP began negotiations
with a likely buyer of the facility. A sale is now expected to be completed by
the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on
an indicative bid by the likely buyer. The estimated loss on disposal is
classified in Asset Impairments on the Consolidated Statements of Operations.
Newgulf's Property, Plant and Equipment, net of accumulated depreciation, of $6
million in 2002 and $17 million in 2001 has been classified on AEP's
Consolidated Balance Sheets as held for sale.
Nordic Trading
In October 2002 AEP announced that its ongoing energy trading operations would
be centered around its generation assets. As a result, AEP took steps to exit
its coal, gas, and electricity trading activities in Europe, except for those
activities necessary to support the U.K. Generation operations. The Nordic
Trading business acquired earlier in 2002 (see Note 12) was made available for
sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3
million, consisted of impairment of goodwill of $4.0 million (see Note 3) and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments on the Consolidated Statements of Operations.
Management's determination of a zero fair value was based on discussions with a
potential buyer. There are no assets and liabilities of Nordic Trading to be
classified on AEP's Consolidated Balance Sheets as held for sale.
Excess Equipment
In November 2002, as a result of a cancelled development project, AEP obtained
title to a surplus gas turbine generator. AEP has been unsuccessful in finding
potential buyers of the unit, including its own internal generation operators,
due to an over-supply of generation equipment available for sale. Sale of the
turbine is now projected before the end of 2003 with an estimated 2002 pre-tax
loss on disposal of $23.9 million, based on market prices of similar equipment.
The loss is included in Asset Impairments on the Consolidated Statements of
Operations. The Other asset of $12 million in 2002 and $31 million in 2001 has
been classified on AEP's Consolidated Balance Sheets as held for sale.
Excess Real Estate
In the fourth quarter of 2002, AEP began to market an under-utilized office
building in Dallas, TX obtained through the merger with CSW. One prospective
buyer has executed an option to purchase the building. Sale of the facility is
projected by second quarter 2003 and an estimated 2002 pre-tax loss on disposal
of $15.7 million has been recorded, based on the option sale price. The
estimated loss is included in Asset Impairments on the Consolidated Statements
of Operations. The Property asset of $18 million in 2002 and $36 million in 2001
has been classified on AEP's Consolidated Balance Sheets as held for sale.
Water Heater Program
AEP operated a program to lease electric water heaters to residential and
commercial customers until a decision was reached in the fourth quarter of 2002
to discontinue the program and to offer the assets for sale. Negotiations are
underway with a qualified buyer, and sale of the assets is projected by the end
of the first quarter of 2003. The estimated 2002 pre-tax loss on disposal of
$3.2 million was based on the expected contract sales price. The loss is
included in Investment Value and Other Impairment Losses on the Consolidated
Statements of Operations. The assets and liabilities have been classified on
AEP's Consolidated Balance Sheets as held for sale. The major classes of assets
held for sale are:
2002 2001
(in millions)
Assets:
Current Assets $ 1 $ 2
Property, Plant and Equipment, Net 38 48
---- ----
Total Assets Held for Sale $39 $50
=== ===
Gas Power Systems
AEP acquired in 2001 a 75% interest in a startup company seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. The
first quarter of 2002, AEP recognized a goodwill impairment loss of $12.2
million due to technological and operating problems (See Note 3). The loss was
recorded in Investment Value and Other Impairment Losses on the Consolidated
Statements of Operations. The fair values of the remaining assets and
liabilities were excluded from AEP's Consolidated Balance Sheets as held for
sale, as the impact was insignificant. AEP's remaining interest was sold in
January 2003.
b. Assets Held and Used
In 2002, AEP recorded the following impairments related to assets (including
Goodwill) held and used to Asset Impairments on the Consolidated Statements of
Operations:
----------------------------- ---------------------------- ------------------
Assets 2002 Pre-Tax Loss Business
Held and Used (in millions) Segment
----------------------------- ---------------------------- ------------------
U.K. Generation $548.7 Wholesale
AEP Coal 59.9 Wholesale
Texas Plants 38.1 Wholesale
Ft. Davis Wind Farm 4.7 Wholesale
----------------------------- ---------------------------- ------------------
Total - ALL
Held and Used
Losses $651.4
----------------------------- ----------------------------
U.K. Generation Plants
In December 2001, AEP acquired two coal-fired generation plants (U.K.
Generation) in the U.K. for a cash payment of $942.3 million and assumption of
certain liabilities. Subsequently and continuing through 2002, wholesale U.K.
electric power prices declined sharply as a result of domestic over-capacity and
static demand. External industry forecasts and AEP's own projections made during
the fourth quarter of 2002 indicate that this situation may extend many years
into the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million, including a goodwill
impairment of $166.1 million as discussed in Note 3. The cash flow analysis used
a discount rate of 6% over the remaining life of the assets and reflected
assumptions for future electricity prices and plant operating costs. This
impairment loss is included in Asset Impairments on the Consolidated Statements
of Operations.
AEP Coal
In October 2001, AEP acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and re-identified as "AEP Coal". During 2002 the coal operations suffered
a decline in forward prices and adverse mining factors that culminated in the
fourth quarter of 2002 and significantly reduced mine productivity and revenue.
Based on an extensive review of economically accessible reserves and other
factors, future mine productivity and production is expected to continue to be
below historical levels. In December 2002, a probability-weighted discounted
cash flow analysis of fair value of the mines was performed which indicated a
2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of
$3.6 million as discussed in Note 3. This impairment loss is included in Asset
Impairments on the Consolidated Statements of Operations.
Texas Plants
In September 2002 AEP proposed closing 16 gas-fired power plants in the ERCOT
control area of Texas (8 TNC plants and 8 TCC plants). ERCOT indicated that it
may designate some of those plants as "reliability must run" (RMR) status. In
October ERCOT designated seven RMR plants (3 TNC plants and 4 TCC plants) and
approved AEP's plan to inactivate nine other plants (5 TNC plants and 4 TCC
plants). The process of moving the plants to inactive status took approximately
two months. Employees of the plants moved to inactive status (approximately 180)
were eligible for severance and outplacement services.
As a result of the decision to inactivate TNC plants, a write-down of utility
assets of approximately $34.2 million (pre-tax) was recorded in Asset
Impairments expense during the third quarter 2002. The decision to inactivate
the TCC plants resulted in a write-down of utility assets of approximately $95.6
million (pre-tax), which was deferred and recorded in Regulatory Assets during
the third quarter 2002.
During the fourth quarter 2002, evaluations continued as to whether assets
remaining at the inactivated plants, including materials, supplies and fuel oil
inventories, could be utilized elsewhere within the AEP System. As a result of
such evaluations, TNC recorded an additional asset impairment charge to Asset
Impairments expense of $3.9 million (pre-tax) in the fourth quarter 2002. In
addition TNC recorded related inventory write-downs of $2.6 million ($1.2
million in Fuel and Purchased Energy: Electricity and $1.4 million in
Maintenance and Other Operation expense). Similarly, TCC recorded an additional
asset impairment write-down of $6.7 million (pre-tax), which was deferred and
recorded in Regulatory Assets in the fourth quarter 2002. TCC also recorded
related inventory write-downs of $14.9 million which was deferred and recorded
in Regulatory Assets in the fourth quarter 2002.
The total Texas plant asset impairment of $38.1 million in 2002 (all related to
TNC) is included in Asset Impairments on the Consolidated Statement of
Operations.
RMR plants are required to ensure the reliability of the power grid, even if
electricity from those plants is not required to meet market needs. ERCOT and
AEP negotiated interim contracts for the seven RMR plants through December 2003,
however, ERCOT has the right to terminate the plants from RMR status upon 90
days written notice.
In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either inactivated or designated as RMR status. See
Texas Restructuring section of the "Customer Choice and Industry Restructuring"
Note 8 for further discussion of the divestiture plan and anticipated timeline.
Ft. Davis Wind Farm
In the 1990's, CSW developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 AEP engineering
staff determined that operation of the facility was no longer technically
feasible and the lease of the underlying site should not be renewed. Dismantling
of the facility will be complete by the end of 2003 with an estimated 2002
pre-tax loss on abandonment of $4.7 million. The loss was recorded in Asset
Impairments on the Consolidated Statements of Operations. The facility will
continue to be classified as held and used until disposal is complete.
c. Investment Values
In 2002, AEP recorded the following declines in fair value on investments
accounted for under APB 18 that were considered to be other than temporarily
impaired as shown in the table below:
----------------------------------- ----------------------- -----------------
Investment Value 2002 Pre-Tax
Impairment Estimated Loss Business
Loss Items (in millions) Segment
----------------------------------- ----------------------- -----------------
Grupo Rede Investment - Brazil $217.0 Other
South Coast Power 63.2 Other
Misc. Technology Investments 11.7 Other
----------------------------------- ----------------------- -----------------
Total $291.9
----------------------------------- ----------------------- -----------------
Grupo Rede Investment
In December 2002, AEP recorded an other than temporary impairment totaling
$141.0 million ($217.0 million net of federal income tax benefit of $76.0
million) of its 44% equity investment in Vale and its 20% equity interest in
Caiua, both Brazilian electric operating companies (referred to as Grupo Rede).
This amount is included in Investment Value and Other Impairment Losses on the
Consolidated Statements of Operations. As of September 30, 2002, AEP had not
recognized its cumulative equity share of operating and foreign currency
translation losses of approximately $88 million and $105 million, respectively,
due to the existence of a put option that permits AEP to require Grupo Rede to
purchase our equity at a minimum price equal to the U.S. dollar equivalent of
the original purchase price. In January 2002 AEP evaluated through an
independent credit assessment the ability of Grupo Rede to fulfill its
responsibilities under the put option and concluded that the carrying value of
the original investment was reasonable.
During 2002, there has been a continuing decline in the Brazilian power industry
and the value of the local currency. Events in the fourth quarter of 2002 led us
to change our view that Grupo Rede would be able to fulfill its responsibilities
under the put option. These events included two downgrades of Caiua debt by
Moody's, resulting in a rating of Caa1. Caiua is an intermediate holding company
which owns substantially all of the utility companies in the Grupo Rede system.
The downgrading of Caiua's credit ratings to a level well below investment grade
casts significant doubt on the ability of Grupo Rede to honor the put option.
Grupo Rede is in the process of restructuring some of its debts, and as a
condition for participating in the restructuring, during November 2002 a
creditor of Grupo Rede requested that AEP agree not to exercise the put option
prior to March 31, 2007. AEP agreed and in exchange received an extension of the
put option from the previous end date of 2009 through 2019. Based on the factors
noted above, AEP could no longer reasonably believe that our investment could be
recovered, resulting in the recording of the impairment.
South Coast Power Investment
South Coast Power is a 50% owned joint venture that was formed in 1996 to build
and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K..
South Coast Power is subject to the same adverse wholesale electric power rates
described for U.K. Generation above. A December 2002 projected cash flow
estimate of the fair value of the investment indicated a 2002 pre-tax other than
temporary impairment of the equity interest (which included the fair value of
supply contracts held by South Coast Power and accounted for in accordance with
SFAS 133) in the amount of $63.2 million. This loss of investment value is
included in Investment Value and Other Impairment Losses on the Consolidated
Statements of Operations.
Technology Investments
AEP previously made investments totaling $11.7 million in four early-stage or
startup technologies involving pollution control and procurement. An analysis in
December 2002 of the viability of the underlying technologies and the projected
performance of the investee companies indicated that the investments were
unlikely to be recovered, and an other than temporary impairment of the entire
amount of the equity interest under APB 18 was recorded. The loss of investment
value is included in Investment Value and Other Impairment Losses on the
Consolidated Statements of Operations.
14. Benefit Plans:
Pension and Other Postretirement Benefits
In the U.S. AEP sponsors two qualified pension plans and two nonqualified
pension plans. Substantially all employees in the U.S. are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. Other
postretirement benefit (OPEB) plans are sponsored by the AEP System to provide
medical and death benefits for retired employees in the U.S.
AEP also has a foreign pension plan for employees of AEP Energy Services U.K.
Generation Limited (Genco) in the U.K. Genco employees participate in their
existing pension plan acquired as part of AEP's purchase of two generation
plants in the U.K. in December 2001.
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, 2002, and a statement of the funded status as of December 31 for
both years:
U.S. Pension Plans U.S. OPEB Plans
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Reconciliation of Benefit
Obligation:
Obligation at January 1 $3,292 $3,161 $ 1,645 $1,668
Service Cost 72 69 34 30
Interest Cost 241 232 114 114
Participant Contributions - - 13 8
Plan Amendments (2) - - 7 (a)
Actuarial (Gain) Loss 258 121 152 192
Divestitures - - - (287)(b)
Benefit Payments (278) (291) (81) (88)
Curtailments - - - 1
------ ------ ------- ------
Obligation at December 31 $3,583 $3,292 $ 1,877 $1,645
====== ====== ======= ======
Reconciliation of Fair Value
of Plan Assets:
Fair Value of Plan Assets at
January 1 $3,438 $3,911 $ 711 $ 704
Actual Return on Plan Assets (371) (182) (57) (31)
Company Contributions 6 - 137 118
Participant Contributions - - 13 8
Benefit Payments (278) (291) (81) (88)
------ ------ ------- ------
Fair Value of Plan Assets at
December 31 $2,795 $3,438 $ 723 $ 711
====== ====== ======= ======
U.S. Pension Plans U.S. OPEB Plans
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Funded Status:
Funded Status at December 31 $ (788) $ 146 $(1,154) $ (934)
Unrecognized Net Transition
(Asset) Obligation (7) (15) 233 263
Unrecognized Prior-Service Cost (13) (12) 6 7
Unrecognized Actuarial
(Gain) Loss 1,020 35 896 649
------ ----- ------ ------
Prepaid Benefit (Accrued
Liability) $ 212 $ 154 $ (19) $ (15)
====== ===== ====== ======
(a) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line.
(b) Related to the sale of Central Ohio Coal Company, Southern Ohio Coal Company
and Windsor Coal Company.
The following table provides the amounts for prepaid benefit costs and accrued
benefit liability recognized in the Consolidated Balance Sheets as of December
31 of both years. The amounts for additional minimum liability, intangible asset
and Accumulated Other Comprehensive Income for 2001 and 2002 were recorded in
2002.
U.S. Pension Plans U.S. OPEB Plans
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Prepaid Benefit Costs $ 255 $ 205 $ - $ 1
Accrued Benefit Liability (44) (51) (19) (16)
Additional Minimum Liability (944) (15) N/A N/A
Intangible Asset 45 9 N/A N/A
Accumulated Other
Comprehensive Income 900 6 N/A N/A
----- ----- ---- ------
Net Asset (Liability) $ 212 $ 154 $(19) $ (15)
===== ===== ==== =====
Other Comprehensive (Income)
Expense Attributable to
Change in Additional Pension
Liability Recognition $ 894 $(4) N/A N/A
===== === ==== ======
N/A = Not Applicable
The value of our qualified plans' assets has decreased from $3.438 billion at
December 31, 2001 to $2.795 billion at December 31, 2002. The qualified plans
paid $272 million in benefits to plan participants during 2002 (nonqualified
plans paid $6 million in benefits). The investment returns and declining
discount rates have changed the status of our qualified plans from overfunded
(plan assets in excess of projected benefit obligations) by $146 million at
December 31, 2001 to an underfunded position (plan assets are less than
projected benefit obligations) of $788 million at December 31, 2002. Due to the
qualified plans currently being underfunded, the Company recorded a charge to
Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax
Asset of $315 million, offset by a Minimum Pension Liability of $662 million and
reduction to prepaid costs and intangible assets of $238 million. The charge to
OCI does not affect earnings or cash flow. Also, because of the recent
reductions in the funded status of our qualified plans, we expect to make cash
contributions to our qualified plans of approximately $66 million in 2003
increasing to approximately $108 million per year by 2005.
The AEP System's qualified pension plans had accumulated benefit obligations in
excess of plan assets of $661 million at December 31, 2002.
The AEP System's nonqualified pension plans had accumulated benefit obligations
in excess of plan assets of $72 million at December 31, 2002 and $66 million at
December 31, 2001. There are no assets in the nonqualified plans.
The AEP System's OPEB plans had accumulated benefit obligations in excess of
plan assets of $1,154 million and $934 million at December 31, 2002 and 2001,
respectively.
The Genco pension plan had $7 million and $10 million at December 31, 2002 and
2001, respectively, of accumulated benefit obligations in excess of plan assets.
The following table provides the components of AEP's net periodic benefit cost
(credit) for the plans for fiscal years 2002, 2001 and 2000:
U.S. Pension Plans U.S. OPEB Plans
2002 2001 2000 2002 2001 2000
(in millions)
Service Cost $ 72 $ 69 $ 60 $ 34 $ 30 $ 29
Interest Cost 241 232 227 114 114 106
Expected Return on Plan Assets (337) (338) (321) (62) (61) (57)
Amortization of
Transition (Asset) Obligation (9) (8) (8) 29 30 41
Amortization of Prior-service
Cost (1) - 13 - - -
Amortization of Net Actuarial
(Gain) Loss (10) (24) (39) 27 18 4
---- ----- ----- ---- ---- ----
Net Periodic Benefit Cost
(Credit) (44) (69) (68) 142 131 123
Curtailment Loss (a) - - - - 1 79
---- ----- ----- ---- ---- ----
Net Periodic Benefit
Cost (Credit) after
Curtailments $ (44) $ (69) $ (68) $142 $132 $202
===== ===== ===== ==== ==== ====
(a) Curtailment charges were recognized during 2000 for the shutdown of Central
Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal Company.
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. Pension Plans U.S. OPEB Plans
2002 2001 2000 2002 2001 2000
Discount Rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected Return on
Plan Assets 9.00 9.00 9.00 8.75 8.75 8.75
Rate of Compensation
Increase 3.7 3.7 3.2 N/A N/A N/A
In determining the discount rate in the calculation of future pension
obligations we review the interest rates of long-term bonds that receive one of
the two highest ratings given by a recognized rating agency. As a result of a
decrease in this benchmark rate during 2002, we determined that a decrease in
our discount rate from 7.25% at December 31, 2001 to 6.75% at December 31, 2002
was appropriate.
For OPEB measurement purposes, a 10% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2003. The rate was assumed
to decrease gradually each year to a rate of 5% through 2008 and remain at that
level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:
1% Increase 1% Decrease
----------- -----------
(in millions)
Effect on total service
and interest cost
components of net
periodic postretirement
health care benefit cost $ 21 $ (17)
Effect on the health care
component of the
accumulated
postretirement
benefit obligation 237 (193)
AEP Savings Plans
AEP sponsors various defined contribution retirement savings plans eligible to
substantially all non-United Mine Workers of America (UMWA) U.S. employees.
These plans include features under Section 401(k) of the Internal Revenue Code
and provide for company matching contributions. Beginning in 2001, AEP's
contributions to the two largest plans increased to 75 cents for every dollar of
the first 6% of eligible employee compensation from the previous rate of 50
cents. The cost for contributions to these plans totaled $60.1 million in 2002,
$55.6 million in 2001 and $36.8 million in 2000.
On January 1, 2003, the two major AEP Savings Plans merged into a single plan.
Other UMWA Benefits
AEP and OPCo, a subsidiary company, 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 2002, 2001 and 2000. In July 2001, OPCo sold certain coal mines in
Ohio and West Virginia.
15. Stock-Based Compensation:
The American Electric Power System 2000 Long-Term Incentive Plan was approved by
shareholders at the Company's annual meeting in 2000 and authorizes the use of
15,700,000 shares of AEP common stock for various types of stock-based
compensation awards, including stock option awards, to key employees. The plan
was adopted in 2000.
Under the plan, the exercise price of all stock option grants must equal or
exceed the market price of AEP's common stock on the date of grant. AEP
generally grants options that have a ten-year life and vest, subject to the
participant's continued employment, in approximately equal 1/3 increments on
January 1st following the first, second and third anniversary of the grant date.
CSW maintained a stock option plan prior to the merger with AEP in 2000.
Effective with the merger, all CSW stock options outstanding were converted into
AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP
stock option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. Outstanding CSW stock options will continue in effect until all
options are exercised, cancelled or expired. Under the CSW stock option plan,
the option price was equal to the fair market value of the stock on the grant
date. All CSW options fully vested upon the completion of the merger and expire
10 years after their original grant date.
A summary of stock option transactions in fiscal periods 2002, 2001 and 2000 is
as follows:
2002 2001 2000
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Options Exercise Options Exercise Options Exercise
(in thousands) Price (in thousands) Price (in thousands) Price
Outstanding at
beginning of year 6,822 $37 6,610 $36 825 $40
Granted 2,923 $27 645 $45 6,046 $36
Exercised (600) $36 (216) $38 (26) $36
Forfeited (358) $41 (217) $37 (235) $39
----- ---- ----
Outstanding at
end of year 8,787 $34 6,822 $37 6,610 $36
===== ===== =====
Options exercisable
at end of year 2,481 $36 395 $43 588 $41
===== === ---
Weighted average Exercise price of options:
-Granted above Market Price $27 - -
-Granted at Market Price $27 $45 $36
The following table summarizes information about stock options outstanding at
December 31, 2002:
Options Outstanding
----------------------------------------------
Range of
Exercise Number Life in Exercise
Prices Outstanding Years Price
---------------------------------------------
$27.06-35.625 8,047,058 8.4 $ 32.54
40.69-49.00 739,483 7.1 44.84
---------------------------------------------
$27.06-49.00 8,786,541 8.3 $ 33.58
---------------------------------------------
Options Exercisable
Range of
Exercise Number Weighted-Average
Prices Outstanding Exercise Price
$27.06-35.625 2,230,000 $35.51
40.69-49.00 251,327 43.66
---------------------------------------------
$27.06-49.00 2,481,327 $36.33
---------------------------------------------
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 in the following table:
-------------------------------------------------------------
2002 2001 2000
---------------------
(in millions
except per share amounts)
Net (loss) income:
As reported $ (519) $ 971 $ 267
Pro forma (528) 959 264
Basic (loss) earnings per share:
As reported $(1.57) $3.01 $0.83
Pro forma (1.59) 2.98 0.82
Diluted (loss) earnings per share:
As reported $(1.57) $3.01 $0.83
Pro forma (1.59) 2.97 0.82
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:
2002 2001 2000
-----------------------------------------------------------
Risk Free Interest
Rate 3.53% 4.87% 5.02%
Expected Life 7 years 7 years 7 years
Expected Volatility 29.78% 28.40% 24.75%
Expected Dividend
Yield 6.15% 6.05% 6.02%
Weighted average fair value of options:
-Granted above
Market Price $4.58 - -
-Granted at
Market Price $4.37 $8.01 $5.50
------------------------------------------------------------
16. Business Segments:
In 2000, AEP reported the following four business segments: Domestic Electric
Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and Other.
With this structure, our regulated domestic utility companies were considered
single, vertically-integrated units, and were reported collectively in the
Domestic Electric Utilities segment.
In 2001 and 2002, we moved toward a goal of functionally and structurally
separating our businesses. The ensuing realignment of our operations resulted in
our current business segments, Wholesale, Energy Delivery and Other. The
business activities of each of these segments are as follows:
Wholesale
o Generation of electricity for sale to retail and wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas, coal and other commodities
o Coal mining, bulk commodity barging operations and other energy supply
related businesses
Energy Delivery
o Domestic electricity transmission
o Domestic electricity distribution
Other
o Energy services
Segment results of operations for the twelve months ended December 31, 2002,
2001 and 2000 are shown below. These amounts include certain estimates and
allocations where necessary.
We have used earnings before interest and income taxes (EBIT) as a measure of
segment operating performance. The EBIT measure is total operating revenues net
of total operating expenses and other income and deductions from income. It
differs from net income in that it does not take into account interest expense,
income taxes and the effect of discontinued operations, extraordinary items and
the cumulative effect of a change in accounting principle. EBIT is believed to
be a reasonable gauge of results of operations. By excluding interest expense
and income taxes, EBIT does not give guidance regarding the demand of debt
service or other interest requirements, or tax liabilities or taxation rates.
The effects of interest expense and taxes on overall corporate performance can
be seen in the Consolidated Statements of Operations. By excluding discontinued
operations, extraordinary items, and the cumulative effect of changes in
accounting principles, EBIT gives more focused guidance on segment operating
performance.
Energy Reconciling AEP
Year Wholesale Delivery Other Adjustments Consolidated
---- --------- -------- ----- ----------- ------------
(in millions)
2002
Revenues from:
External unaffiliated
customers $10,988 $ 3,551 $ 16 $ - $14,555
Transactions with other
operating segments 2,314 20 46 (2,380) -
Segment EBIT 645 970 (549) - 1,066
Depreciation, depletion and
amortization expense 842 519 16 - 1,377
Total assets 22,622 11,624 248 247(a) 34,741
Investments in equity method
subsidiaries 115 - 57 - 172
Gross property additions 1,072 638 12 - 1,722
2001
Revenues from:
External unaffiliated
customers $ 9,297 $ 3,356 $ 114 $ - $12,767
Transactions with other
operating segments 2,708 20 1,155 (3,883) -
Segment EBIT 1,302 986 42 - 2,330
Depreciation, depletion and
amortization expense 597 632 14 - 1,243
Total assets 21,947 12,455 220 4,675(a) 39,297
Investments in equity method
subsidiaries 242 - 370 - 612
Gross property additions 610 844 200 - 1,654
2000
Revenues from:
External unaffiliated
customers $ 7,834 $ 3,174 $ 105 $ - $11,113
Transactions with other
operating segments 1,726 2 750 (2,478) -
Segment EBIT 686 1,017 89 - 1,792
Depreciation, depletion and
amortization expense 556 506 29 - 1,091
Total assets 24,172 14,876 2,625 4,960(a) 46,633
Investments in equity method
subsidiaries 140 - 296 - 436
Gross property additions 366 961 141 - 1,468
(a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or
Assets of Discontinued Operations.
17. 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 Executive
Committee and are administered by the Chief Risk Officer. The Risk Executive
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. of
Market Risk Oversight, and senior financial and operating managers.
The risks and related strategies that management can employ are:
Risk Description Strategy
----- ------------ ---------
Price Risk Volatility in Trading and
commodity prices hedging
Interest Rate Risk Changes in
interest rates Hedging
Foreign Exchange Fluctuations in
Risk foreign currency Trading and
rates hedging
Credit Risk Non-performance Guarantees
on contracts and collateral
with counterparties
We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree other commodities and as a result we are
subject to price risk. The amount of risk taken by the traders is controlled by
the management of the trading operations and the Chief Risk Officer and his
staff. If the risk from trading activities exceeds certain pre-determined
limits, the positions are modified or hedged to reduce the risk to be within the
limits unless specifically approved by the Risk Executive Committee.
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 a settlement agreement in
Michigan, capped in Indiana and fixed (subject to future commission action) in
West Virginia. To the extent all fuel supply for the generating units in these
states is not under fixed price long-term contracts, AEP is subject to market
price risk. AEP continues to be protected against market price changes by active
fuel clauses in Arkansas, Kentucky, Louisiana, Oklahoma, Virginia and the SPP
area of Texas.
We enter into currency and interest rate forward and swap transactions to hedge
the currency and interest rate exposures created by commodity transactions.
These transactions are marked-to-market to match the change in value in the
transactions they hedge which are also marked-to-market. We employ forward
contracts as cash flow hedges and swaps as cash flow or fair value hedges to
mitigate changes in interest rates or fair values on Short-Term Debt and
Long-term Debt when management deems it necessary. We do not hedge all interest
rate risk.
We employ cash flow forward hedge contracts to lock-in prices on transactions
denominated in foreign currencies where deemed 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.
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 are valued based on forward price curves which represent a
series of projected 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.
Option 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, the implied volatility curve and the implied
correlation curve. Volatility and correlation prices may be quoted in the
market. Significant estimates in valuing these contracts include forward price
curves, volumes, and other volatilities.
Futures and options traded on exchanges (primarily oil and gas on NYMEX) are
valued at the exchange price.
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. When this
occurs, we use our best judgment to estimate the curve values. 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 curve to the market. All
fair value amounts are net of adjustments for items such as credit quality of
the counterparty (credit risk) and liquidity risk.
We also mark-to-market derivatives that are not trading contracts in accordance
with generally accepted accounting principles. There may be unique models for
these transactions, but the curves the Company inputs into the models are the
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.
Results of Risk Management Activities
The amounts of net revenue margins (sales less purchases) in 2002, 2001, and
2000 for trading activities were:
2002 2001 2000
---- ---- ----
(in millions)
Net Revenue
Margins $53 $402 $233
The fair value of open trading contracts that are marked-to-market are based on
management's best estimates using over-the-counter quotations and exchange
prices for short-term open trading contracts, and internally developed price
curves for open long-term trading contracts. The following table does not
reflect derivative contracts designated as hedges or firm transmission rights
contracts. As a result, the totals will not agree to the Consolidated Balance
Sheets. The fair values of trading contracts at December 31 are:
2002 2001
------------------ --------------------
Fair Fair
Value Value
(in millions) (in millions)
Trading Assets
Electricity and Other
Physicals $ 846 $ 966
Financials 226 170
------ -------
Total Trading Assets $1,072 $ 1,136
====== =======
Gas
Physicals $ 105 $ 196
Financials 685 1,587
------ -------
Total Trading Assets $ 790 $ 1,783
====== =======
Trading Liabilities
Electricity and Other
Physicals $ (534) $ (760)
Financials (126) (87)
------ -------
Total Trading Liabilities $ (660) $ (847)
====== =======
Gas
Physicals $ (191) $ (38)
Financials (761) (1,586)
------ -------
Total Trading Liabilities $ (952) $(1,624)
====== =======
Credit Risk
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 counterparties depending upon credit quality 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 are not material to our financial
condition at December 31, 2002. At December 31, 2002, less than 7% of our
exposure was below investment grade as expressed in terms of Net Mark to Market
Assets. Net Mark to Market Assets represents the aggregate difference between
the forward market price for the remaining term of the contract and the
contractual price per counterparty. The following table approximates
counterparty credit quality and exposure for AEP based on netting across AEP
entities, commodities and instruments.
Counterparty Futures,
Credit Quality: Forward and
Swap
Contracts Options Total
Year Ending
December 31, 2002
(in millions)
AAA/Exchanges $ 26 $ 2 $ 28
AA 307 33 340
A 448 26 474
BBB 700 101 801
Below Investment
Grade 107 11 118
----- --- -----
Total $1,588 $173 $1,761
====== ==== ======
We enter into transactions for electricity and natural gas as part of wholesale
trading operations. Electricity and gas transactions are executed
over-the-counter with counterparties or through brokers. Gas transactions are
also executed through brokerage accounts with brokers who are registered with
the U.S. 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,
2002 and 2001 were $109 million and $55 million. These margin accounts are
restricted and therefore are not included in Cash and Cash Equivalents on the
Consolidated Balance Sheets. AEP and its subsidiaries can be subject to further
margin requirements should related commodity prices change.
Financial Derivatives and Hedging
In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. AEP recorded a favorable
transition adjustment to Accumulated Other Comprehensive Income of $27 million
at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives
included in the transition adjustment are interest rate swaps, foreign currency
swaps and commodity swaps, options and futures.
Most of the derivatives identified in the trans-ition adjustment were designated
as cash flow hedges and relate to foreign operations.
Certain derivatives may be designated for accounting purposes as a hedge of
either the fair value of an asset, liability, firm commitment, or a hedge of the
variability of cash flows related to a variable-priced asset, liability,
commitment, or forecasted trans-action. To qualify for hedge accounting, the
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 to determine whether the hedge will be or
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 the
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. 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 (Loss) on
the Consolidated Balance Sheets at December 31, 2002 are:
Accumulated
Other Comprehensive
Hedging Assets Hedging Liabilities Income (Loss) After Tax
(in millions)
Electricity and Gas $6 $ (8) $ (2)
Interest Rate - (13)* (12)
Foreign Currency - (2) (2)
----
$(16)
* Includes $6 million loss recorded in an equity investment.
The following table represents the activity in Other Comprehensive Income (Loss)
related to the effect of adopting SFAS 133 for derivative contracts that qualify
as cash flow hedges at December 31, 2002:
(in millions)
AEP Consolidated
Beginning Balance, January 1, 2002 $ (3)
Changes in fair value (56)
Reclasses from OCI to net loss 43
---
Accumulated OCI derivative loss, December 31, 2002 $(16)
====
Approximately $9 million of net losses from cash flow hedges in Accumulated
Other Comprehensive Income (Loss) at December 31, 2002 are expected to be
reclassified to net income in the next twelve months as the items being hedged
settle. The actual amounts reclassified from Accumulated Other Comprehensive
Income to Net Income can differ as a result of market price changes. The maximum
term for which the exposure to the variability of future cash flows is being
hedged is five years.
FINANCIAL INSTRUMENTS
Market Valuation of Non-Derivative Financial Instrument
The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term
Debt and Accounts Payable approximate fair value because of the short-term
maturity of these instruments. The book value of the pre-April 1983 spent
nuclear fuel disposal liability approximates the best estimate of its fair
value.
The fair values of Long-term Debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange. The book values and fair values of significant financial
instruments for AEP at December 31, 2002 and 2001 are summarized in the
following tables.
2002 2001
Book Value Fair Value Book Value Fair Value
---------- ---------- ---------- ----------
(in millions) (in millions)
Long-term Debt $10,125 $10,470 $9,505 $9,542
Preferred Stock 84 77 95 93
Trust Preferred Securities 321 324 321 321
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 "Accounting for Certain Investments in Debt and Equity
Securities". At December 31, 2002 and 2001, the fair values of the trust
investments were $969 million and $933 million, respectively, and had a cost
basis of $909 million and $839 million, respectively. The change in market value
in 2002, 2001, and 2000 was a net unrealized holding loss of $33 million and $11
million and a net unrealized holding gain of $6 million, respectively.
18. Income Taxes:
The details of AEP's consolidated income taxes before discontinued operations,
extraordinary items, and cumulative effect as reported are as follows:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Federal:
Current $ 330 $404 $ 793
Deferred (192) 60 (236)
----- ---- -----
Total 138 464 557
----- ---- -----
State:
Current 32 61 47
Deferred 30 34 (6)
----- ---- -----
Total 62 95 41
----- ---- -----
International:
Current 13 (13) 4
Deferred 1 - -
----- ---- ------
Total 14 (13) 4
----- ---- -----
Total Income Tax
as Reported
Before
Discontinued
Operations,
Extraordinary
Items and
Cumulative
Effect $ 214 $546 $ 602
===== ==== =====
The following is a reconciliation of the difference between the amount of
federal income taxes computed by multiplying book income before federal income
taxes by the statutory tax rate, and the amount of income taxes reported.
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Net Income (Loss) $(519) $ 971 $267
Discontinued Operations (net of income tax
Of $73 million in 2002, $22 million in 2001
and $5 million in 2000) 190 (86) (122)
Extraordinary Items
(net of income tax of $20 million in 2001
and $44 million in 2000) - 50 35
Cumulative Effect of Accounting Change
(net of income tax of $2 million in 2001) 350 (18) -
Preferred Stock Dividends 11 10 11
----- ------ ----
Income Before Preferred Stock Dividends
of Subsidiaries 32 927 191
Income Taxes Before Discontinued Operations,
Extraordinary Items and Cumulative Effect 214 546 602
----- ------ ----
Pre-Tax Income $ 246 $1,473 $793
===== ====== ====
Income Taxes on Pre-Tax Income
at Statutory Rate (35%) $ 86 $ 516 $278
Increase (Decrease) in Income Taxes
Resulting from the Following Items:
Depreciation 32 48 77
Corporate Owned Life Insurance - 4 247
Investment Tax Credits (net) (35) (37) (36)
Tax Effects of International Operations 123 (12) (1)
Energy Production Credits (14) - -
Merger Transaction Costs - - 49
State Income Taxes 40 62 26
Other (18) (35) (38)
----- ------ ----
Total Income Taxes as Reported before
Discontinued Operations, Extraordinary
Items and Cumulative Effect $ 214 $ 546 $602
===== ====== ====
Effective Income Tax Rate 87.0% 37.1% 75.9%
===== ====== ====
The following tables show the elements of the net deferred tax liability and
the significant temporary differences:
December 31,
--------------------------
2002 2001
---- ----
(in millions)
Deferred Tax Assets $ 2,189 $ 1,216
Deferred Tax Liabilities (6,105) (5,716)
------- -------
Net Deferred Tax Liabilities $(3,916) $(4,500)
======= =======
Property Related Temporary Differences $(3,612) $(3,674)
Amounts Due From Customers For Future
Federal Income Taxes (360) (245)
Deferred State Income Taxes (422) (314)
Transition Regulatory Assets (234) (268)
Regulatory Assets Designated for Securitization (310) (332)
Asset Impairments and Investment Value Losses 417 -
Deferred Income Taxes on Other Comprehensive Loss 326 3
All Other (net) 279 330
------- -------
Net Deferred Tax Liabilities $(3,916) $(4,500)
======= =======
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 6th
Circuit.
19. Basic and Diluted Earnings Per Share:
The calculation of basic and diluted earnings (loss) per common share (EPS) is
based on the amounts of Net Income (Loss) and weighted average common shares
shown in the table below:
2002 2001 2000
---- ---- ----
(in millions - except
per share amounts)
Income:
Income Before Discontinued
Operations, Extraordinary
Items and Cumulative
Effect $ 21 $ 917 $ 180
Discontinued Operations (190) 86 122
------ ----- -----
Income (Loss) Before
Extraordinary Item
And Cumulative Effect (169) 1,003 302
Extraordinary Losses
(net of tax):
Discontinuance of
Regulatory Accounting
For Generation - (48) (35)
Loss on Reacquired Debt - (2) -
Cumulative Effect of
Accounting Change
(net of tax) (350) 18 -
----- ----- -----
Net Income (Loss) $(519) $ 971 $ 267
===== ====== =====
Weighted Average Shares:
Average Common
Shares Outstanding 332 322 322
Assumed Conversion of
Dilutive Stock Options
(see Note 15) - 1 -
----- ----- -----
Diluted Average Common
Shares Outstanding 332 323 322
===== ===== =====
Basic and Diluted
Earnings Per Common Share:
Income Before Discontinued
Operations, Extraordinary
Items and Cumulative
Effect $ 0.06 $2.85 $0.56
Discontinued Operations (0.57) 0.26 0.38
------ ----- -----
Income (Loss) Before
Extraordinary Item and
Cumulative Effect (0.51) 3.11 0.94
Extraordinary Losses
(net of tax):
Discontinuance of
Regulatory Accounting
For Generation - (0.15) (0.11)
Loss on Reacquired Debt - (0.01) -
Cumulative Effect
of Accounting Change
(net of tax) (1.06) 0.06 -
------ ----- -----
$(1.57) $3.01 $0.83
====== ===== =====
The assumed conversion of stock options does not affect net earnings (loss) for
purposes of calculating diluted earnings per share. Basic and diluted EPS are
the same in 2002, 2001 and 2000 since the effect on weighted average common
shares outstanding is minimal.
Had AEP recognized net income in fiscal 2002, incremental shares attributable to
the assumed exercise of outstanding stock options would have increased diluted
common shares outstanding by 398,000 shares.
Options to purchase 8.8 million, 0.7 million and 6.4 million shares of common
stock were outstanding at December 31, 2002, 2001 and 2000, respectively, but
were not included in the computation of diluted earnings per share because the
options' exercise prices were greater than the year-end market price of the
common shares and, therefore, the effect would be antidilutive.
In addition, there is no effect on diluted earnings per share related to our
equity units (issued in 2002) unless the market value of AEP common stock
exceeds $49.08 per share. There were no dilutive effects from equity units at
December 31, 2002. If our common stock value exceeds $49.08 we would apply the
treasury stock method to the equity units to calculate diluted earnings per
share. This method of calculation theoretically assumes that the proceeds
received as a result of the forward purchase contracts are used to repurchase
outstanding shares. Also see Note 27.
20. Supplementary Information:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
AEP Consolidated Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $142 $127 $86
Cash was Paid for:
Interest (net of capitalized amounts) 792 972 842
Income Taxes 336 569 449
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases 6 17 118
Assumption of Liabilities Related to Acquisitions 1 171 -
Exchange of Communication Investment for Common Stock - 5 -
21. Power and Distribution 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 1,113 MW.
Investments in power projects that are 50% or less owned are accounted for by
the equity method and reported in Investments in Power and Distribution Projects
on the Consolidated Balance Sheets (see "Eastex" within the Assets Held for Sale
section of Note 13), except for Eastex Cogeneration which, due to its structure,
is consolidated. At December 31, 2002, six domestic power projects and three
international power investments are accounted for under the equity method. The
six domestic projects are combined cycle gas turbines that provide steam to a
host commercial customer and are considered either Qualifying Facilities (QFs)
or Exempt Wholesale Generators (EWGs) under PURPA. The three international power
investments are classified as Foreign Utility Companies (FUCO) under the Energy
Policies Act of 1992. Two of the international investments are power projects
and the other international investment is a company which owns an interest in
four additional power projects. All of the power projects accounted for under
the equity method have unrelated third-party partners.
Seven of the above power projects have project-level financing, which is
non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $58 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits.
Distribution Projects
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. In December 2002, AEP
recorded an other than temporary impairment totaling $141.1 million (after
federal income tax benefit of $76 million) of its 44% equity investment in Vale
and its 20% equity interest in Caiua. See "Grupo Rede Investment" within the
Investment Values section of Note 13 "Asset Impairments and Investment Value
Losses", for further information on the 2002 impairment of our Vale and Caiua
investments.
22. Leases:
Leases of property, plant and equipment are for periods up to 99 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment for regulated
operations. Capital leases for non-regulated property are accounted for as if
the assets were owned and financed. The components of rental costs are as
follows:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Lease Payments on
Operating Leases $346 $293 $246
Amortization of
Capital Leases 65 82 118
Interest on
Capital Leases 14 22 36
---- ---- ----
Total Lease Rental
Costs $425 $397 $400
==== ==== ====
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
-----------
2002 2001
---- ----
(in millions)
Property, Plant and
Equipment:
Production $ 40 $ 39
Distribution 15 15
Other 687 723
---- ----
Total Property, Plant and
Equipment 742 777
Accumulated Amortization 299 250
---- ----
Net Property, Plant
and Equipment $443 $527
==== ====
Obligations Under Capital
Leases:
Noncurrent Liability $170 $219
Liability Due Within
One Year 58 75
---- ----
Total $228 $294
==== ====
Future minimum lease payments consisted of the following at December 31, 2002
Noncancelable
Capital Operating
Leases Leases
------- --------------
(in millions)
2003 $ 70 $ 305
2004 53 271
2005 37 252
2006 29 242
2007 21 237
Later Years 59 2,462
---- ------
Total Future
Minimum Lease
Payments 269 $3,769
======
Less Estimated
Interest Element 41
Estimated Present
Value of Future
Minimum Lease
Payments $228
====
OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated
unconsolidated special purpose entity. JMG has a capital structure of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from pollution control bonds and other bonds. JMG owns the
Gavin Scrubber and leases it to OPCo. The lease is accounted for as an
operating lease with the payment obligations included in the lease footnote.
Payments under the operating lease are based on JMG's cost of financing (both
debt and equity) and include an amortization component plus the cost of
administration. Neither OPCo nor AEP has an ownership interest in JMG and does
not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial
15-year lease term is non-cancelable. At the end of the initial term, OPCo can
renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or
sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition
cost, OPCo must pay the difference to JMG.
The use of JMG allows AEP to enter into an operating lease while keeping the tax
benefits otherwise associated with a capital lease. As of December 31, 2002,
unless the structure of this arrangement is changed, it is reasonably possible
that AEP will consolidate JMG in the third quarter of 2003 as a result of the
issuance of FIN 46. Upon consolidation, AEP would record the assets,
liabilities, depreciation expense, minority interest and debt interest expense
of JMG. AEP would eliminate operating lease expense. AEP's maximum exposure to
loss as a result of its involvement with JMG is approximately $560 million of
outstanding debt and equity of JMG as of December 31, 2002.
AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.
23. Lines of Credit and Sale of Receivables:
Lines of Credit - AEP System
The AEP System uses short-term debt, primarily commercial paper and revolving
credit facilities, to meet fluctuations in working capital requirements and
other interim capital needs. AEP has established a utility money pool and a
non-utility money pool to coordinate short-term borrowings for certain
subsidiaries. AEP also incurs borrowings outside of the money pool for other
subsidiaries. As of December 31, 2002, AEP had revolving credit facilities
totaling $3.5 billion to support its commercial paper program. At December 31,
2002, AEP had $3.2 billion outstanding in short-term borrowings of which $1.4
billion was commercial paper supported by the revolving credit facilities. The
maximum amount of commercial paper outstanding during the year, which had a
weighted average interest rate during 2002 of 2.47%, was $3.3 billion during
April 2002. On December 11, 2002, Moody's Investor Services placed AEP's Prime-2
short-term rating for commercial paper under review for possible downgrade. On
January 24, 2003, Standard & Poor's Rating Services placed AEP's A-2 short-term
rating for commercial paper under review for possible downgrade. On February 10,
2003, Moody's Investor Services downgraded AEP's short-term rating for
commercial paper to Prime-3 from Prime-2. As a result, AEP's access to the
commercial paper market will be limited and AEP will use other sources of funds
as necessary.
Outstanding Short-term Debt for AEP Consolidated consisted of:
December 31,
2002 2001
(in millions)
Balance Outstanding:
Notes Payable $1,747 $1,063
Commercial paper 1,417 2,948
------ ------
Total $3,164 $4,011
====== ======
Sale of Receivables - AEP Credit
AEP Credit entered into a sale of receivables agreement with a group of banks
and commercial paper conduits. Under the sale of receivables agreement, which
expires May 28, 2003, AEP Credit sells an interest in the receivables it
acquires to the commercial 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 and
allowing AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities in
accordance with GAAP. We continue to service the receivables. This off-balance
sheet transaction was entered into to allow AEP credit to repay its outstanding
debt obligations, continue to purchase the AEP operating companies' receivables,
and accelerate its cash collections.
At December 31, 2002, the sale of receivables agreement provided the banks and
commercial paper conduits would purchase a maximum of $600 million of
receivables from AEP Credit, of which $454 million was outstanding. As
collections from receivables sold occur and are remitted, the outstanding
balance for sold receivables is reduced and as new receivables are sold, the
outstanding balance of sold receivables increases. All of the receivables sold
represented affiliate receivables. The commitment's new term under the sale of
receivables agreement will remain at $600 million until May 28, 2003. AEP Credit
maintains a retained interest in the receivables sold and this interest is
pledged as collateral for the collection of the efareceivables sold. The fair
value of the retained interest is based on book value due to the short-term
nature of the accounts receivables less an allowance for anticipated
uncollectible accounts.
AEP Credit purchases accounts receivable through purchase agreements with
affiliated companies and, until the first quarter of 2002, with non-affiliated
companies. As a result of the restructuring of electric utilities in the State
of Texas, the purchase agreement between AEP Credit and Reliant Energy,
Incorporated was terminated as of January 25, 2002 and the purchase agreement
between AEP Credit and Texas-New Mexico Power Company, the last remaining
non-affiliated company, was terminated on February 7, 2002. In addition, the
purchase agreements between AEP Credit and its Texas affiliates AEP Texas
Central Company (formerly Central Power and Light Company) and AEP Texas North
Company (formerly West Texas Utilities Company) were terminated effective March
20, 2002.
Comparative accounts receivable information for AEP Credit:
Year Ended December 31,
----------------------
2002 2001
---- ----
(in millions)
Proceeds from Sale of
Accounts Receivable $5,513 $1,134
Accounts Receivable
Retained Interest Less
Uncollectible Accounts
and Amounts Pledged as
Collateral 76 143
Deferred Revenue from
Servicing Accounts
Receivable 1 5
Loss on Sale of Accounts
Receivable 4 8
Average Variable
Discount Rate 1.92% 2.28%
Retained Interest if 10%
Adverse Change in
Uncollectible Accounts 74 142
Retained Interest if 20%
Adverse Change in
Uncollectible Accounts 72 140
Historical loss and delinquency amount for the AEP System's customer accounts
receivable managed portfolio:
Face Value
Year Ended December 31,
----------------------
2002 2001
---- ----
(in millions)
Customer Accounts Receivable Retained $ 466 $ 343
Miscellaneous Accounts Receivable Retained 1,394 1,365
Allowance for Uncollectible Accounts Retained (119) (69)
------ ------
Total Net Balance Sheet Accounts Receivable 1,741 1,639
Customer Accounts Receivable Securitized (Affiliate) 454 560
Customer Accounts Receivable Securitized (Non-Affiliate) - 485
------ ------
Total Accounts Receivable Managed $2,195 $2,684
====== ======
Net Uncollectible Accounts Written Off $ 49 $ 87
====== ======
Customer accounts receivable retained and securitized for the domestic electric
operating companies are managed by AEP Credit. Miscellaneous accounts receivable
have been fully retained and not securitized.
At December 31, 2002, delinquent customer accounts receivable for the electric
utility affiliates that AEP Credit currently factors was $30 million.
24. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows:
2002 Quarterly Periods Ended
----------------------------
March 31 June 30 Sept. 30 Dec. 31
(In Millions - Except -------- ------- -------- -------
Per Share Amounts)
Revenues $ 3,169 $ 3,575 $ 3,870 $ 3,941
Operating Income (Loss) 459 427 782 (405)
Income (Loss) Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect 159 158 386 (682)
Net Income (Loss) (169) 62 425 (837)
Earnings (Loss) per Share
Before Discontinued
Operations,
Extraordinary Items
And Cumulative Effect* 0.49 0.49 1.14 (2.01)
Earnings (Loss) per
Share** (0.53) 0.19 1.25 (2.47)
2001 Quarterly Periods Ended
----------------------------
March 31 June 30 Sept. 30 Dec. 31
(In Millions - Except -------- ------- -------- -------
Per Share Amounts)
Revenues $2,910 $3,259 $ 3,733 $ 2,865
Operating Income 521 622 824 215
Income Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect 230 251 399 37
Net Income 266 232 421 52
Earnings per Share Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect*** 0.72 0.77 1.23 0.12
Earnings per Share**** 0.83 0.72 1.31 0.16
* Amounts for 2002 do not add to $0.06 earnings per share before discontinued
operations, extraordinary items and cumulative effect due to rounding and the
dilutive effect of shares issued in 2002.
**Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.
***Amounts for 2001 do not add to $2.85 earnings per share before discontinued
operations, extraordinary items and cumulative effect due to rounding.
****Amounts for 2001 do not add to $3.01 earnings per share due to rounding.
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
for the fourth quarter 2002 decreased $896 million from the prior year due to
the impairment loss and impairment value losses of approximately $1,188 million
(pre-tax) to reduce the valuation of under-performing assets. In addition to the
impairments that were booked during the fourth quarter, a change in other
comprehensive income of $585 million for pension liability had a negative effect
on the Consolidated Balance Sheets.
25. Trust Preferred Securities:
The following Trust Preferred Securities issued by the wholly-owned statutory
business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2002 and
December 31, 2001. They are classified on the Consolidated 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. TCC
reacquired 490,000 trust preferred units during 2001.
Units Issued/ Description of
Outstanding Underlying
Business Trust Security At 12/31/02 Amount at December 31, Debentures of Registrant
-------------- -------- ------------- ---------------------- ------------------------
(in millions)
2002 2001
CPL Capital I 8.00%, Series A 5,450,000 $136 $136 TCC, $141 million,
8.00%, Series A
PSO Capital I 8.00%, Series A 3,000,000 75 75 PSO, $77 million,
8.00%, Series A
SWEPCo Capital I 7.875%, Series A 4,400,000 110 110 SWEPCO, $113 million,
---------- ---- - ---
7.875%, Series A
12,850,000 $321 $321
========== ==== ====
Each of the business trusts is treated as a subsidiary of its parent company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified above. In addition to the obligations under
their subordinated debentures, each of the parent companies has also agreed to a
security obligation which represents a full and unconditional guarantee of its
capital trust obligation.
26. Minority Interest in Finance Subsidiary:
In August 2001 AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne)
and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated
subsidiary of AEP that was capitalized with the assets of Houston Pipe Line
Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million
of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary
and parent of SubOne) preferred stock, that is convertible into AEP common stock
at market price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an unconditional
obligation to fund $83 million from SubOne and $750 million from Steelhead
Investors LLC ("Steelhead" - non-controlling preferred member interest). As
managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and has a capital structure of $750 million of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to
limit its risk associated with Houston Pipe Line Company and Louisiana
Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead receives a
quarterly preferred return equal to an adjusted floating reference rate (4.784%
and 4.413% for the quarters ended December 31, 2002 and 2001, respectively).
Caddis has the right to redeem Steelhead's interest at any time.
The $750 million invested in Caddis by Steelhead was loaned to SubOne. This
intercompany loan to SubOne is due August 2006, and is supported by the natural
gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4
million of preferred stock in AEP Gas Holding. The preferred stock is
convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if SubOne were to reduce its loan with Caddis by $225 million. The credit
agreement between Caddis and SubOne contains covenants that restrict certain
incremental liens and indebtedness, asset sales, investments, acquisitions, and
distributions. The credit agreement also contains covenants that impose minimum
financial ratios. Non-performance of these covenants may result in an event of
default under the credit agreement. Through December 31, 2002, we have complied
with the covenants contained in the credit agreement. In addition, a default
under any other agreement or instrument relating to AEP and certain
subsidiaries' debt outstanding in excess of $50 million is an event of default
under the credit agreement.
The initial period of Steelhead's investment in Caddis is through August 2006.
At the end of the initial period, Caddis will either reset Steelhead's return
rate, re-market Steelhead's interests to new investors, redeem Steelhead's
interests, in whole or in part including accrued return, or liquidate Caddis in
accordance with the provisions of applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events including a default in the payment of the preferred
return, Steelhead's rights include: forcing a liquidation of Caddis and acting
as the liquidator, and requiring the conversion of the AEP Gas Holding preferred
stock into AEP common stock. If Steelhead exercised its rights to force Caddis
to liquidate under these conditions, then AEP would evaluate whether to
refinance at that time or relinquish the assets that support the intercompany
loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are separate and
legally distinct from AEP. The results of operations, cash flows and financial
position of Caddis and SubOne are consolidated with AEP for financial reporting
purposes. Steelhead's investment in Caddis and payments made to Steelhead from
Caddis are currently reported on AEP's income statement and balance sheet as
Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with Steelhead is
$321.4 million of preferred stock, $83 million under the subscription agreement
to Caddis for any losses incurred by Caddis and the cash reserve fund balance of
$34 million (as of December 31, 2002) due Caddis for default under the
intercompany loan agreement. AEP can reduce its maximum exposure related to the
preferred stock by a reduction of $225 million of the intercompany loan.
As of December 31, 2002, we are continuing to review the application of FIN
46 as it relates to the Steelhead transaction.
27. Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per unit and received
proceeds of $345 million. Each equity unit consists of a forward purchase
contract and a senior note.
The forward purchase contracts obligate the holders to purchase shares of AEP
common stock on August 16, 2005. The purchase price per equity unit is $50. The
number of shares to be purchased under the forward purchase contract will be
determined under a formula based upon the average closing price of AEP common
stock near the stock purchase date. Holders may satisfy their obligation to
purchase AEP common stock under the forward purchase contracts by allowing the
senior notes to be remarketed or by continuing to hold the senior notes and
using other resources as consideration for the purchase of stock. If the holders
elect to allow the notes to be remarketed, the proceeds from the remarketing
will be used to purchase a portfolio of U.S. treasury securities that the
holders will pledge to AEP in order to meet their obligations under the forward
purchase contracts.
The senior notes have a principal amount of $50 each and mature on August 16,
2007. The senior notes are the collateral that secures the holders' requirement
to purchase common stock under the forward purchase contracts.
AEP will make quarterly interest payments on the senior notes at the initial
annual rate of 5.75%. The interest rate can be reset through a remarketing,
which is initially scheduled for May 2005. AEP will make contract adjustment
payments to the purchaser at the annual rate of 3.50% on the forward purchase
contracts. The present value of the contract adjustment payments has been
recorded as a $31 million liability in Equity Unit Senior Notes offset by a
charge to Paid-in Capital. Interest payments on the senior notes are reported as
interest expense. Accretion of the contract adjustment payment liability is
reported as interest expense.
AEP aplies the treasury stock method to the equity units to calculate diluted
earnings per share. This method of calculation theoretically assumes that
the proceeds received as a result of the forward purchase contract are used
to purchase outstanding shares.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
December 31, 2002
Call
Price per Shares Shares Amount (In
Share(a) Authorized(b) Outstanding(f) Millions)
--------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 608,150 $ 61
----
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 333,100 33
6.02% - 6-7/8% (c) $100 1,650,000 513,450 51
----
Total Subject to Mandatory
Redemption (c) 84
----
Total Preferred Stock $145
====
December 31, 2001
Call
Price per Shares Shares Amount (In
Share(a) Authorized(b) Outstanding(f) Millions)
---------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 614,608 $ 61
----
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) 250,000 100,000 10
----
Total Subject to Mandatory
Redemption (c) 95
----
Total Preferred Stock $156
====
NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call
price plus accrued dividends. The involuntary liquidation preference is
$100 per share for all outstanding shares.
(b) As of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and
7,713,501 shares of $100, $25 and no par value preferred stock,
respectively, that were authorized but unissued.
(c) Shares outstanding and related amounts are stated net of applicable
retirements through sinking funds(generally at par) and reacquisitions
of shares in anticipation of future requirements. The subsidiaries
reacquired enough shares in 1997 to meet all sinking fund requirements
on certain series until 2008 and on certain series until 2009 when all
remaining outstanding shares must be redeemed.
(d) Not callable prior to 2003, after that the call price is $100 per share
plus accrued dividends.
(e) With sinking fund.
(f) The number of shares of preferred stock redeemed is 106,458 shares
in 2002, 50,000 shares in 2001 and 209,563 shares in 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Long-term Debt of Subsidiaries
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
-------- ------------- ----------------------------- -----------
December 31, 2002 2002 2001 2002 2001
----------------- ---- ---- ---- ----
(in millions)
FIRST MORTGAGE BONDS (a)
2002-2004 6.87% 6.00%-7.85% 6.00%-7.85% $ 648 $ 1,246
2005-2008 6.90% 6.20%-8% 6.20%-8% 463 699
2022-2025 7.66% 6.875%-8.7% 6-7/8%-8.80% 773 850
INSTALLMENT PURCHASE CONTRACTS (b)
2002-2009 4.62% 3.75%-7.70% 1.80%-7.70% 396 446
2011-2030 5.83% 1.35%-8.20% 1.55%-8.20% 1,284 1,234
NOTES PAYABLE (c)
2002-2021 5.54% 3.732%-9.60% 4.048%-9.60% 520 217
SENIOR UNSECURED NOTES
2002-2005 5.53% 2.12%-7.45% 2.31%-7.45% 1,834 1,910
2006-2012 5.91% 4.31%-6.91% 6.125%-6.91% 2,295 1,727
2032-2038 6.64% 6.00%-7-3/8% 7.20%-7-3/8% 690 340
JUNIOR DEBENTURES
2025-2038 7.90% 7.60%-8.72% 7.60%-8.72% 205 618
SECURITIZATION BONDS
2003-2016 5.40% 3.54%-6.25% - 797 -
OTHER LONG-TERM DEBT (d) 247 258
Unamortized Discount (net) (32) (40)
------- -------
Total Long-term Debt
Outstanding 10,120 9,505
Less Portion Due Within One Year 1,633 1,095
------- -------
Long-term Portion $ 8,487 $ 8,410
======= =======
EQUITY UNIT SENIOR NOTES
2007 5.75% 5.75% - $ 376 $ -
======= =======
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) First mortgage bonds are secured by first mortgage liens on electric
property, plant and equipment.
(b) For certain series of installment purchase contracts interest rates are
subject to periodic adjustment. Certain series will be purchased on demand
at periodic interest-adjustment dates. Letters of credit from banks and
standby bond purchase agreements support certain series.
(c) Notes payable represent outstanding promissory notes issued under term loan
agreements and revolving credit agreements with a number of banks and other
financial institutions. At expiration all notes then issued and
outstanding are due and payable. Interest rates are both fixed and
variable. Variable rates generally relate to specified short-term interest
rates.
(d) Other long-term debt consists of a liability along with accrued interest for
disposal of spent nuclear fuel (see Note 9 of the Notes to Consolidated
Financial Statements) and financing obligation under sale lease back
agreements.
Long-term debt outstanding at December 31, 2002 (includes Equity Unit Senior
Notes) is payable as follows:
(in millions)
2003 $ 1,633
2004 824
2005 993
2006 1,611
2007 1,081
Later Years 4,386
-------
10,528
Unamortized Discount 32
-------
Total $10,496
MANAGEMENT'S RESPONSIBILITY
The management of American Electric Power Company, Inc. has prepared the
financial statements and schedules herein and is responsible for the integrity
and objectivity of the information and representations in this annual report,
including the consolidated financial statements. These statements have been
prepared in conformity with accounting principles generally accepted in the
United States of America, using informed estimates where appropriate, to reflect
the Company's financial condition and results of operations. The information in
other sections of the annual report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for determining
that management has fulfilled its obligation in the preparation of the financial
statements and in the ongoing examination of the Company's established internal
control structure over financial reporting. The Audit Committee, which consists
solely of outside directors and which reports directly to the Board of
Directors, meets regularly with management, 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.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of American
Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001,
and the related consolidated statements of operations, cash flows and common
shareholders' equity and comprehensive income, for each of the three years in
the period ended December 31, 2002. These financial statements are the
responsibility of the 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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of American Electric
Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Company
adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1,
2002.
As discussed in Note 13 to the consolidated financial statements, the Company
recorded certain impairments of goodwill, long-lived assets and other
investments in the fourth quarter of 2002.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
INVESTOR INQUIRIES
Investors should direct inquiries to Investor Relations using the toll free
number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of
Investor Relations American Electric Power Service Corporation 28th Floor 1
Riverside Plaza Columbus, OH 43215-2373
FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities and Exchange Commission will
be available in April 2003 at no cost to shareholders. Please address requests
for copies to:
R. Todd Rimmer
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH 43215-2373
TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK
Equiserve Trust Company, N.A.
P.O. Box 43069
Providence, RI 02940-3069
Phone Number: 1-800-328-6955
Hearing Impaired Number: TDD: 1-800-952-9245
Website: http://www.equiserve.com