Appendix A to the
Proxy Statement
American Electric Power
Audited Consolidated Financial Statements and
Management's Discussion and Analysis
AMERICAN ELECTRIC POWER
1 Riverside Plaza
Columbus, Ohio 43215-2373
Contents
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Glossary of Terms
Forward-Looking Information
Selected Consolidated Financial Data
Management's Financial Discussion and Analysis of Results of Operations
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Common Shareholders' Equity and Comprehensive
Income (Loss)
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
Schedule of Consolidated Long-term Debt
Index to Notes to Consolidated Financial Statements
Independent Auditors' Report
Management's Responsibility
AEP COMMON STOCK AND DIVIDEND INFORMATION
-----------------------------------------
The AEP common stock quarterly high and low sales prices, quarter-end
closing price and the cash dividends paid per share are shown in the
following table:
Quarter-end
Quarter Ended High Low Closing Price Dividend
------------- ---- --- ------------- -----------
December 2003 $30.59 $26.69 $30.51 $0.35
September 2003 30.00 26.58 30.00 0.35
June 2003 31.51 22.56 29.83 0.35
March 2003 30.63 19.01 22.85 0.60
December 2002 $30.55 $15.10 $27.33 $0.60
September 2002 40.37 22.74 28.51 0.60
June 2002 48.80 39.00 40.02 0.60
March 2002 47.08 39.70 46.09 0.60
AEP common stock is traded principally on the New York Stock Exchange. At
December 31, 2003, AEP had approximately 150,000 registered shareholders.
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 other true-up items and the recovery of such amounts.
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 and consolidated affiliates.
AEP Credit AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated domestic electric utility companies.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCo.
AEPES AEP Energy Services, Inc., a subsidiary of AEPR.
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 System Power Pool or Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of Pool
AEP Power Pool 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.
ALJ Administrative Law Judge.
Alliance RTO Alliance Regional Transmission Organization, 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.
APB 18 Accounting Principles Board Opinion Number 18: The Equity Method of Accounting for Investments in
Common Stock.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission Arkansas Public Service Commission.
Buckeye Buckeye Power, 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.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary. 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.
DETM Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE United States Department of Energy.
ECOM Excess Cost Over Market.
EITF The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3 Emerging Issues Task Force Issue No. 02-3: Issues Involved in Accounting for Derivative Contracts
Held For Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities.
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.
FIN 45 FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others."
FIN 46 FASB Interpretation No. 46, "Consolidation of Variable Interest Entities."
FUCOs Foreign Utility Companies.
GAAP Generally Accepted Accounting Principles.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR Interchange Cost Reconstruction.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
ISO Independent System Operator.
JMG JMG Funding LP.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
KV Kilovolt.
KWH Kilowatthour.
LIG Louisiana Intrastate Gas, an AEP subsidiary.
LPSC Louisiana Public Service Commission.
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.
MW Megawatt.
MWH Megawatthour.
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.
NRC Nuclear Regulatory Commission.
OCC The Corporation Commission of the State of Oklahoma.
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.
PTB Price-to-Beat.
PUCO The Public Utilities Commission of Ohio.
PUCT The Public Utility Commission of Texas.
PUHCA Public Utility Holding Company Act of 1935, as amended.
PURPA The Public Utility Regulatory Policies Act of 1978.
RCRA Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC
and TNC.
REP Retail Electric Provider.
Risk Management Contracts Trading and non-trading derivatives, including those derivatives designated as cash flow and fair
value hedges, and non-derivative contracts held for trading purposes that were subject
to mark-to-market accounting prior to January 1, 2003.
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.
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SFAS 101 Statement of Financial Accounting Standards No. 101,
Accounting for the Discontinuance of Application of Statement 71.
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SFAS 133 Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
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SFAS 143 Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations.
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SFAS 149 Statement of Financial Accounting Standards No. 149,
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
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SFAS 150 Statement of Financial Accounting Standards No. 150,
Accounting for Certain Financial Instruments with Characteristics of both Liabilities
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and Equity.
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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.
Tenor Maturity of a contract.
Texas Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas. TNC AEP Texas
North Company, an AEP electric utility subsidiary.
TVA Tennessee Valley Authority.
U.K. The United Kingdom.
VaR Value at Risk, a method to quantify risk exposure.
Virginia SCC Virginia State Corporation Commission.
WVPSC Public Service Commission of West Virginia.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
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 and certain of its subsidiaries contains
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and each of its registrant
subsidiaries believe that their expectations are based on reasonable
assumptions, any such statements may be influenced by factors that could
cause actual outcomes and results to be materially different from those
projected. Among the factors that could cause actual results to differ
materially from those in the forward-looking statements are:
. Electric load and customer growth.
. Weather conditions.
. Available sources and costs of fuels.
. Availability of generating capacity and the performance of AEP's
generating plants.
. The ability to recover regulatory assets and stranded costs in
connection with deregulation.
. New legislation and government regulation including requirements for
reduced emissions of sulfur, nitrogen, mercury, carbon and other
substances.
. Resolution of pending and future rate cases, negotiations and other
regulatory decisions (including rate or other recovery for
environmental compliance).
. Oversight and/or investigation of the energy sector or its
participants.
. Resolution of litigation (including pending Clean Air Act enforcement
actions and disputes arising from the bankruptcy of Enron Corp.).
. AEP's ability to reduce its operation and maintenance costs.
. The success of disposing of investments that no longer match AEP's
corporate profile.
. AEP's ability to sell assets at attractive prices and on other
attractive terms.
. International and country-specific developments affecting foreign
investments including the disposition of any current foreign
investments.
. The economic climate and growth in AEP's service territory and
changes in market demand and demographic patterns.
. Inflationary trends.
. AEP's ability to develop and execute on a point of view regarding
prices of electricity, natural gas, and other energy-related
commodities.
. Changes in the creditworthiness and number of participants in the
energy trading market.
. Changes in the financial markets, particularly those affecting the
availability of capital and AEP's ability to refinance existing debt
at attractive rates.
. Actions of rating agencies, including changes in the ratings of debt
and preferred stock.
. Volatility and changes in markets for electricity, natural gas, and
other energy-related commodities.
. Changes in utility regulation, including the establishment of a
regional transmission structure.
. Accounting pronouncements periodically issued by accounting
standard-setting bodies.
. The performance of AEP's pension plan.
. Prices for power that we generate and sell at wholesale.
. Changes in technology and other risks and unforeseen events,
including wars, the effects of terrorism (including increased
security costs), embargoes and other catastrophic events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
OPERATIONS STATEMENTS DATA (in millions)
- ------------------------------------------------------
Total Revenues $14,545 $13,308 $12,753 $10,743 $ 9,695
Operating Income 1,632 1,804 2,223 1,758 2,053
Income Before Discontinued Operations, Extraordinary
Items and Cumulative Effect 522 485 960 177 865
Discontinued Operations Income (Loss) (605) (654) 41 134 116
Extraordinary Losses - - (48) (44) (9)
Cumulative Effect of Accounting Changes Gain (Loss) 193 (350) 18 - -
Net Income (Loss) 110 (519) 971 267 972
BALANCE SHEET DATA
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Property, Plant and Equipment $36,033 $34,127 $32,993 $31,472 $30,476
Accumulated Depreciation and Amortization 14,004 13,539 12,655 12,398 11,895
-------- -------- -------- -------- --------
Net Property, Plant and Equipment $22,029 $20,588 $20,338 $19,074 $18,581
======== ======== ======== ======== ========
Total Assets $36,744 $35,890 $40,432 $47,703 $36,297
Common Shareholders' Equity 7,874 7,064 8,229 8,054 8,673
Cumulative Preferred Stocks
of Subsidiaries (a) (d) 137 145 156 161 182
Trust Preferred Securities (b) - 321 321 334 335
Long-term Debt (a) (b) 14,101 10,190 9,409 8,980 9,471
Obligations Under Capital Leases (a) 182 228 451 614 610
COMMON STOCK DATA
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Earnings (Loss) per Common Share:
Before Discontinued Operations, Extraordinary Items
and Cumulative Effect $ 1.35 $ 1.46 $ 2.98 $ 0.55 $ 2.69
Discontinued Operations (1.57) (1.97) 0.13 0.42 0.36
Extraordinary Losses - - (0.16) (0.14) (0.02)
Cumulative Effect of Accounting Changes 0.51 (1.06) 0.06 - -
-------- -------- -------- -------- --------
Earnings (Loss) Per Share $ 0.29 $ (1.57) $ 3.01 $ 0.83 $ 3.03
======== ======== ======== ======== ========
Average Number of Shares Outstanding (in millions) 385 332 322 322 321
Market Price Range:
High $ 31.51 $ 48.80 $ 51.20 $ 48.94 $ 48.19
Low 19.01 15.10 39.25 25.94 30.56
Year-end Market Price 30.51 27.33 43.53 46.50 32.13
Cash Dividends on Common (c) $ 1.65 $2.40 $ 2.40 $ 2.40 $ 2.40
Dividend Payout Ratio(c) 569.0% (152.9)% 79.7% 289.2% 79.2%
Book Value per Share $ 19.93 $ 20.85 $ 25.54 $ 25.01 $ 26.96
(a) Including portion due within one year.
(b) See Note 17 of the Notes to Consolidated Financial Statements.
(c) Based on AEP historical dividend rate.
(d) Includes Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory
Redemption which are classified in 2003 as Non-Current Liabilities.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
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American Electric Power Company, Inc. (AEP) is one of the largest investor owned
electric public utility holding companies in the U.S. Our electric utility
operating companies provide generation, transmission and distribution service to
more than five million retail customers in Arkansas, Indiana, Kentucky,
Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West
Virginia.
We have a vast portfolio of assets including:
. 38,000 megawatts of generating capacity, the largest complement of
generation in the U.S., the majority of which has a significant cost
advantage in many of our market areas. Utility generating capacity of
4,500 megawatts located in Texas and approximately 280 megawatts of
independent power generation located in Colorado and Florida are
expected to be sold during 2004
. 39,000 miles of transmission lines, the backbone of the electric
interconnection grid in the Eastern U.S.
. 210,000 miles of distribution lines that deliver electricity to
customers
. Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37
towboats and two coal handling terminals with 20 million tons of annual
capacity)
. 6,400 miles of gas pipelines in Louisiana and Texas with 127 Bcf of gas
storage facilities. We have entered into an agreement to sell 2,000
miles of pipeline and plan to sell 9 Bcf of storage located in Louisiana
related to our disposal of LIG
. 4,000 megawatts of generating capacity in the U.K., a market which we
plan to exit by the end of 2004
BUSINESS STRATEGY
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We will continue to concentrate our efforts on our domestic utilities. Our
objectives are to be an economical, reliable and safe provider of energy to the
markets that we serve. We will achieve economic advantage by designing,
building, improving and operating low cost efficient sources of power and
maximizing the volumes of power delivered from these facilities. We will
maintain and enhance our position as a safe and reliable provider of energy by
making significant investments into environmental and reliability upgrades. We
will seek to recover the cost of our new utility investments in a manner that
results in reasonable rates for our customers and that provides a fair return
for our shareholders through a stable stream of cash flows enabling us to pay
competitive dividends.
We are addressing many challenges in our unregulated business. We have
substantially reduced our trading activities that are not related to the sale of
power from our owned-generation. We have written down the value of several
investments to reflect deterioration in market conditions and sold or plan to
sell assets that no longer fit our core business strategy. We have identified
certain assets as "held-for-sale" and will move others to "held-for-sale" as we
formalize and approve our plans for disposition. We will continue to operate HPL
as we evaluate our future plans for this investment.
In summary our business strategy calls for us to:
Operations
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. Invest in technology that improves the environment of the communities in
which we operate
. Maximize the value of our transmission assets and protect our revenue
stream through membership in PJM
. Continue maintaining and improving distribution service quality
. Optimize generation assets by increasing availability and consequently
increasing sales
. Complete the sales of our non-core assets
Regulation
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. Focus on the regulatory process to maximize our earnings while providing
fair and reasonable rates to our customers
. Complete the sale of our generation assets in Texas and recognize and
recover the associated stranded costs in compliance with the law
. Complete the integration of the operation of our transmission system
into PJM consistent with applicable regulatory requirements
Financial
---------
. Operate only those unregulated investments that are consistent with our
energy expertise and risk tolerance and that provide reasonable
prospects for a fair return and moderate growth
. Continue to improve credit quality and maintain acceptable levels of
liquidity
. Achieve moderate but steady earnings growth
2003 OVERVIEW
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2003 was a year of transition for AEP. We repositioned ourselves to take
advantage of, and maximize, the value of our utility assets. At the same time we
took significant strides to exit non-core investments.
Our utility operations had a year of continued improvement resulting from strong
wholesale results and our efforts to control and reduce operating costs. We
reduced our losses from unregulated investments by reducing transitional trading
losses and cutting related administrative expenses.
During 2003 we further stabilized our financial strength by:
. Issuing approximately $1.1 billion in common stock
. Completing a cost reduction initiative which led to a $392 million
decline in operations and maintenance expenses during 2003 as compared
to 2002. Savings of approximately $139 million are attributable to our
utility operations
. Minimizing future capital requirements associated with non-core assets
. Reducing our cash flow risk by limiting our trading activities to a
level consistent with the scope of our generation fleet
. Stabilizing our credit ratings
We have redirected our business strategy by:
. Continuing to streamline our trading activities principally to support
the sale of power from our core assets
. Actively pursuing the sale of all of our U.K. generation and our gas
pipeline operations located in Louisiana; we expect each of these
dispositions to be completed during 2004
OUTLOOK FOR 2004
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We remain focused on the fundamental earning power of our utilities, and we are
committed to strengthening our balance sheet. Our strategy for achieving these
goals is well planned. We will:
. Continue to identify opportunities to further reduce both our
operations and maintenance expenses and to efficiently manage our
capital expenditures
. Seek rate changes that are fair and reasonable and that allow us to
make the necessary operational and environmental improvements to our
system
. Dispose of various unregulated assets to eliminate the negative
earnings and cash consequences of these operations
. Use the proceeds from our dispositions to reduce debt and strengthen
our capital structure
. Successfully operate certain unregulated investments such as our wind
farms and our barge and river transport groups, which compliment our
core capabilities
. Evaluate opportunities to hold and operate HPL under a revised business
model that reduces commodity risk and earns reasonable returns for
shareholders
Our objective is excellence in operations and results. There are, nevertheless,
certain risks and challenges. We discuss these matters in detail in the Notes to
Financial Statements and later in Management's Discussion and Analysis under the
heading of Significant Factors. We will diligently resolve these matters by
finding workable solutions that balance the interests of our customers, our
employees and our investors.
RESULTS OF OPERATIONS
- ---------------------
In 2003, AEP's principal operating business segments and their major activities
were:
. Utility Operations:
. Domestic generation of electricity for sale to retail and
wholesale customers
. Domestic electricity transmission and distribution
. Investments-Gas Operations:*
. Gas pipeline and storage services
. Investments-UK Operations:**
. International generation of electricity for sale to wholesale
customers
. Coal procurement and transportation to AEP plants and third
parties
. Investments-Other:
. Coal mining, bulk commodity barging operations and other energy
supply related businesses
* Operations of Louisiana Intrastate Gas were classified as discontinued
during 2003.
** UK Operations were classified as discontinued during 2003.
American Electric Power Company's consolidated Net Income (Loss) for the years
ended December 31, 2003, 2002 and 2001 were as follows (Earnings and Average
Shares Outstanding in millions):
2003 2002 2001
--------------------- ---------------------- ----------------------
Earnings EPS Earnings EPS Earnings EPS
-------- --- -------- --- -------- ---
Utility Operations $1,218 $ 3.17 $1,154 $ 3.47 $941 $2.92
Investments - Gas Operations (290) (.76) (99) (.29) 91 .28
Investments - UK Operations - - - - - -
Investments - Other (277) (.72) (522) (1.58) - -
All Other* (129) (.34) (48) (.14) (72) (.22)
------- ------- ------- ------- ----- ------
Income Before Discontinued
Operations, Extraordinary Items
and Cumulative Effect 522 1.35 485 1.46 960 2.98
Investments - Gas Operations (91) (.24) 8 .02 (4) (.01)
Investments - UK Operations (507) (1.32) (472) (1.42) (41) (.13)
Investments - Other (7) (.01) (190) (.57) 86 .27
------- ------- ------- ------- ----- ------
Discontinued Operations (605) (1.57) (654) (1.97) 41 .13
Extraordinary Loss - - - - (48) (.16)
Cumulative Effect of
Accounting Changes 193 .51 (350) (1.06) 18 .06
------- ------- ------- ------- ----- ------
Total Net Income (Loss) $ 110 $ .29 $ (519) $(1.57) $971 $3.01
======= ======= ======= ======= ===== ======
Average Shares Outstanding 385 332 322
======= ======= ======
* All Other includes the parent company interest income and expense, as well as
other non-allocated costs.
2003 Compared to 2002
- ---------------------
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
in 2003 increased compared to 2002 due to increased wholesale earnings, lower
impairment and other charges, and reduced operations and maintenance expenses.
This increase was offset, in part, by milder weather and continuing weakness in
the economy. Our Net Income for 2003 of $110 million or $.29 per share includes
a loss, net of taxes, on discontinued operations of $605 million and $193
million of income, net of taxes, from the cumulative effect of changing our
accounting for asset retirement obligations and for certain trading activities.
Our Net Loss for 2002 of $519 million or ($1.57) per share includes a loss, net
of taxes, on discontinued operations of $654 million and a $350 million, net of
tax, charge for implementing a newly issued accounting pronouncement related to
the impairment of goodwill. During the fourth quarter of 2003 we concluded that
the U.K. operations and LIG were not part of our core business and we began
actively marketing each of these investments. The U.K. operations consist of our
generation and trading operations that sell to wholesale customers. LIG's
operations include 2,000 miles of intrastate gas pipelines and 9 Bcf of natural
gas storage capacity. In addition, we recognized that poor market conditions
also affected our merchant generation, other gas pipeline and storage assets,
goodwill associated with these investments and various other assets. Based on
market factors, as measured by a combination of indicative bids from unrelated
interested buyers, independent appraisals, and estimates of cash flows, we
recognized impairment losses of $960 million, net of taxes.
Average shares outstanding increased to 385 million in 2003 from 332 million in
2002 due to a common stock issuance in March 2003. The additional average shares
outstanding decreased our 2003 earnings per share by $0.04.
2002 Compared to 2001
- ---------------------
Our Net Loss was $519 million or a loss of $1.57 per share in 2002 which was a
$1.5 billion decline from 2001. Income Before Discontinued Operations,
Extraordinary Items and Cumulative Effect was negatively affected by plant
availability, lower wholesale prices, reduced trading activity and write-offs to
reduce the valuation of the under-performing assets. In the fourth quarter 2002,
we recognized impairments on under-performing assets and recorded losses, net of
taxes, of $854 million. The losses in the fourth quarter 2002 were caused by the
extended decline in domestic and international energy markets. In addition to
the fourth quarter impairment losses, we had losses on discontinued operations
of $654 million including U.K. operations, SEEBOARD, Citipower and other
investments and a loss for transitional goodwill impairment of $350 million
related to SEEBOARD and Citipower that resulted from the adoption of a newly
issued accounting standard related to the impairment of goodwill.
Our results of operations are discussed below according to our operating
segments.
Utility Operations
- ------------------
Summary of Selected Sales Data
For Utility Operations
For the Years Ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
Energy Summary (in millions of KWH)
Retail
Residential 45,479 46,805 43,498
Commercial 37,104 36,487 35,589
Industrial 51,856 53,686 52,443
Miscellaneous 3,035 3,216 2,208
-------- -------- --------
Total 137,474 140,194 133,738
-------- -------- --------
Wholesale 72,977 70,661 79,288
-------- -------- --------
2003 2002 2001
---- ---- ----
Weather Summary (in degree days)
Eastern Region
- --------------
Actual - Heating 5,314 4,963 4,679
Normal - Heating* 5,182 5,177 5,232
Actual - Cooling 757 1,252 1,021
Normal - Cooling* 975 1,013 997
Western Region
- --------------
Actual - Heating 1,020 1,044 1,134
Normal - Heating* 1,062 1,034 1,060
Actual - Cooling 2,220 2,369 2,377
Normal - Cooling* 2,217 2,224 2,233
* Normal Heating/Cooling represents the 30-year average of degree days.
2003 Compared to 2002
- ---------------------
Earnings from Utility Operations increased $64 million to $1,218 million in
2003. Decreased operating expenses were partially offset by decreases in
revenues net of related fuel and purchased power.
Utility revenues net of related fuel and purchased power decreased as follows:
. Residential demand decreased principally as a consequence of milder
weather, and industrial demand was down due to the continued slow
economic recovery. The combination of these factors reduced revenues net
of related fuel and purchased power by approximately $65 million.
. Reserves for final fuel factor decisions in Texas as well as other
disallowances and associated rate reserves of $102 million and lower
regulatory deferrals for ECOM-based stranded costs of $44 million
reduced earnings. The provisions for stranded cost recovery in Texas
recognize a regulatory asset or liability for the difference between the
actual price received from the state-mandated auction of 15% of
generation capacity and the earlier estimate of market price derived by
a PUCT model.
. Fuel and purchased power costs increased by approximately $40 million
due in part to nuclear plant outages.
. During the fourth quarter of 2002, we exited trading activities that
were not related to the sale of power from our owned-generation. The
loss of these contributions from exiting the related trading positions
reduced utility earnings by approximately $70 million.
The decreases in utility revenues net of related fuel and purchased power were
partially offset as follows:
. Off-system sales, including optimization activities, increased by
approximately $160 million primarily due to increased prices and plant
availability.
. Transmission revenues increased by approximately $45 million, due
principally to increased wholesale power sales volumes.
Utility operating expenses decreased as follows:
. Maintenance and Other Operation expense decreased $139 million due to
continuing efforts to reduce costs, primarily labor and insurance,
despite severe storm damage in the Midwest.
. Taxes Other Than Income Taxes decreased $17 million primarily due to
reduced gross receipts tax as a result of the sale of the Texas REPs.
. Depreciation and Amortization expense decreased $18 million due to the
change in our accounting for asset retirement obligations. The
accounting change caused similar offseting increases in Maintenance and
Other Operation expenses.
2002 Compared to 2001
- ---------------------
Earnings from Utility Operations increased $213 million to $1,154 million in
2002 due to an $84 million gain on the sale of the Texas REPs and capital cost
reductions of $104 million, partially offset by a reduction in operating income.
Capital costs decreased due to reductions in short-term interest rates, lower
outstanding balances of short-term debt and the refinancing of long-term debt at
favorable interest rates. These reductions were partially offset by an increase
in the amount of long-term debt outstanding.
Increased operating expenses were partially offset by increases in revenues net
of related fuel and purchased power.
Utility revenues net of related fuel and purchased power increased as follows:
. ECOM-based Texas stranded cost deferrals increased $262 million.
. Retail demand increased approximately $180 million due to increased
usage by residential customers. Eastern region cooling degree days were
up 23% over 2001.
The increases in utility revenues net of related fuel and purchased power were
partially offset as follows:
. Off-system sales net of related fuel and purchased power decreased $126
million primarily due to lower plant availability, lower wholesale
prices, the loss of certain municipal and co-op customers, and customers
switching from FERC tariff-based to market-based rates.
. Trading operations, which decreased $214 million as a result of our
previously announced plan to exit trading activities that are not
related to the sale of power from our owned-generation.
Utility operating expenses increased as follows:
. Maintenance and Other Operation expense increased $102 million due to
increased benefit costs of $48 million, increased post September 11
insurance cost of $35 million and increased nuclear maintenance and
other expenses of $19 million.
. Depreciation and Amortization expense increased $46 million as a result
of additional generation, transmission and distribution assets.
. Taxes Other Than Income Taxes increased $70 million due to increased
property and payroll taxes.
Investments - Gas Operations
- ----------------------------
2003 Compared to 2002
- ---------------------
The loss from our Gas Operations of $290 million increased $191 million from
2002. This increase is primarily due to impairments recorded to reflect the
reduction in the value of our gas assets. In the fourth quarter 2003, we
recognized impairments and other related charges of $228 million, net of tax,
associated with HPL assets and goodwill based on market indicators supported by
indicative bids received for LIG. These bids led us to conclude that purchasers
were no longer willing to pay higher multiples for historic cash flows which
included trading activities. Our previous operating strategy included higher
risk tolerances associated with trading activities in order to achieve such
operating results.
Partially offsetting the 2003 impairments, gas operations earnings have improved
approximately $68 million from 2002 due to a $40 million decrease in losses
associated with the options trading portfolio that we are no longer actively
trading and exiting through a transition plan (our transition gas trading
portfolio) and a $28 million reduction in operating expenses. These earnings
improvements were partially offset by $15 million of losses due to unexpected
late February 2003 sales to Entex, at fixed prices, when the Houston Ship
Channel prices were at historic highs, a decrease in March deliveries due to
unseasonably mild weather, and a decline in trading optimization of $28 million
due to lower risk tolerances and limits compared to the previous year.
2002 Compared to 2001
- ---------------------
The loss from our Gas Operations of $99 million increased $190 million from
2001. The increase is due to significant trading losses in 2002 compared with
strong trading results in 2001.
Investments - UK Operations
- ---------------------------
2003 Compared to 2002
- ---------------------
The loss from our UK Operations of $507 million for 2003 increased by $35
million from 2002 and was due primarily to $375 million, net of tax, of
impairment and other related charges recorded during the fourth quarter. During
2003, we concluded that the UK Operations were not part of our core business and
we began actively marketing our investment. As a result, we devalued our UK
investment based on bids received from interested unrelated buyers. The loss
includes $157 million of pre-tax losses associated with commitments for below
market forward sales of power, which are beyond the date of the anticipated sale
of these plants. We also experienced operating losses as a result of the
deterioration of pretax trading margins of $83 million associated with U.K.
power and $29 million associated with coal and freight.
2002 Compared to 2001
- ---------------------
Our loss in 2002 from UK Operations of $472 million increased by $431 million
from 2001. Our operations in the U.K. were dramatically expanded in December
2001 with the acquisition of two 2,000 MW generation stations. Goodwill and
asset impairment charges of $414 million, net of tax, contributed to our 2002
losses. The oversupply conditions throughout 2002 worsened in the fourth quarter
after the British government's decision to subsidize British Energy, a
financially troubled, dominant generator of power in the U.K. This intervention
in the competitive market kept inefficient generation in the marketplace. The
write-down of our two U.K. power plants was the result of our analyses that
indicated U.K. power prices would not recover to levels that would permit us to
carry the plants at their original purchase prices. In addition to unfavorable
U.K. power and coal markets, higher than anticipated operating costs contributed
to the loss in 2002.
Investments - Other
- -------------------
2003 Compared to 2002
- ---------------------
The loss from our Other investments decreased by $245 million to $277 million in
2003. The decrease was primarily due to asset impairment charges of $257
million, net of tax, compared to impairments of $392 million, net of tax,
recorded in 2002. 2003 impairments included losses of $45 million, net of tax,
for two of our independent generation facilities due to market conditions; $168
million, net of tax, for the Dow facility due to the current market conditions
and litigation; and coal mining asset impairments of $44 million, net of tax,
based on bids from unrelated parties. Additionally we incurred lower
international development costs and reduced interest expenses during 2003.
2002 Compared to 2001
- ---------------------
The loss from our Other investment operations of $522 million resulted from $392
million of asset impairment charges, net of tax. These write-downs in the fourth
quarter of 2002 recognized the lower valuation in our investments in a utility
in Brazil, AEP Communications and other under-performing assets. There were no
such write-downs in 2001.
All Other
- ---------
Our parent company's 2003 expenses increased $81 million over 2002 primarily
from higher interest costs due to increased debt at the parent level and reduced
reliance on short-term borrowings as well as the recognition of estimated losses
from certain litigation contingencies. Expenses in 2002 declined $24 million
from 2001 due to lower interest costs.
FINANCIAL CONDITION
- -------------------
We measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows. During 2003 we improved our financial
condition as a consequence of the following actions and events:
. We issued approximately $1.1 billion of new common equity
. We reduced our quarterly dividend in June 2003 to $.35 per share which
reduced our annualized cash outflows by approximately $395 million
. We reduced short-term debt by $2.8 billion, restructured our lines of
credit into two $750 million facilities, completed approximately $1.3
billion of optional long-term debt redemptions, paid-off $225 million of
our Steelhead financing, and funded $1.4 billion of debt maturities
. We limited our energy trading activity to levels necessary to optimize
earnings from sales of our owned-generation
. Despite downgrades of certain debt ratings during the first quarter and
continued uncertainty in the industry, we have maintained stable credit
ratings across the AEP System
Capitalization
- --------------
2003 2002 2001
---- ---- ----
Common Equity 35% 32% 36%
Preferred Stock 1 1 1
Long-term Debt, including amounts due within one year 63 50 43
Short-term Debt 1 14 17
Minority Interest in Finance Subsidiary - 3 3
---- ---- ----
Total Capitalization 100% 100% 100%
==== ==== ====
Our capital was affected by the following, during 2003:
. We recognized $960 million of impairment losses related to our
unregulated investments while reducing our ratio of debt to total
capital
. We substantially reduced our short-term debt commitments, thereby
reducing refinancing and cash flow risks
. We improved our percentage of common equity outstanding to total
capitalization, in part through the issuance of approximately $1.1
billion of new equity.
Liquidity
- ---------
Liquidity, or access to cash, is an important factor in determining our
financial stability due to volatility in wholesale power prices and the effects
of credit rating downgrades. We are committed to preserving an adequate
liquidity position.
Credit Facilities
- -----------------
We manage our liquidity by maintaining adequate external financing commitments.
We had an available liquidity position of approximately $3.5 billion as
illustrated in the table below:
Amount Maturity
------ --------
(in millions)
Commercial Paper Backup:
Lines of Credit $ 750 May 2004
Lines of Credit 1,000 May 2005
Lines of Credit 750 May 2006
Euro Revolving Credit
Facility 189 October 2004
Letter of Credit Facility 200 September 2006
------
Total 2,889
Available Cash and Temporary
Investments 920*
------
Total Liquidity Sources 3,809
Less: AEP Commercial Paper
Outstanding 282**
Letters of Credit
Outstanding 35
------
Net Available Liquidity $3,492
======
* Available Cash and Temporary Investments of $920 million and $262
million in unavailable cash on hand make up the $1.2 billion Cash and
Cash Equivalents balance on our Consolidated Balance Sheet at December
31, 2003.
** Amount does not include JMG Funding LP (JMG) commercial paper
outstanding in the amount of $26 million. This commercial paper is
specifically associated with the Gavin scrubber lease. This commercial
paper does not reduce available liquidity to AEP.
Debt Covenants
- --------------
Our revolving credit agreements require us to maintain our percentage of debt to
total capitalization at a level that does not exceed 67.5%. The method for
calculating our outstanding debt and other capital is contractually defined. At
December 31, 2003, this percentage was 58.8%. Non-performance of these covenants
may result in an event of default under these credit agreements. At December 31,
2003, we complied with the covenants contained in these credit agreements. In
addition, the acceleration of the payment obligations of us, or certain of our
subsidiaries, prior to maturity under any other agreement or instrument relating
to debt outstanding in excess of $50 million would cause an event of default
under these credit agreements and permit the lenders to declare the amounts
outstanding thereunder payable.
Our commercial paper backup facilities generally prohibit new borrowings if we
experience a material adverse change in our business or operations. We may,
however, make new borrowings under these facilities if we experience a material
adverse change so long as the proceeds of such borrowings are used to repay
outstanding commercial paper.
Under an SEC order, AEP and its utility subsidiaries cannot incur additional
indebtedness if the issuer's common equity would constitute less than 30% (25%
for TCC due to its securitization bonds) of its capital. In addition, this order
restricts AEP and the utility subsidiaries from issuing long-term debt unless
that debt will be rated investment grade by at least one nationally recognized
statistical rating organization.
Dividend Restrictions
- ---------------------
Provisions within the Articles of Incorporation relating to the preferred stock
of certain of our subsidiaries restrict the payment of cash dividends or other
distributions on their common and preferred stock. PUHCA prohibits our
subsidiaries from making loans or advances to the parent company, AEP. In
addition, under PUHCA, AEP and its public utility subsidiaries can only pay
dividends out of retained or current earnings.
Credit Ratings
- --------------
We also manage our liquidity by continuing to maintain investment grade credit
ratings and a stable credit outlook and are taking steps to improve our credit
quality, including plans during 2004 to further reduce our outstanding debt
through the use of proceeds from the planned dispositions. If we receive a
downgrade in our credit ratings by these agencies, our borrowing costs could
increase. The rating agencies currently have AEP and our rated subsidiaries on
stable outlook. Current ratings for AEP are as follows:
Moody's S&P Fitch
------- --- -----
AEP Short-Term Debt P-3 A-2 F-2
AEP Senior Unsecured Debt Baa3 BBB BBB
Cash Flow
- ---------
Our cash flows are a major factor in managing and maintaining our liquidity
strength.
2003 2002 2001
---- ---- ----
(in millions)
Cash and Cash Equivalents at Beginning of Period $ 1,199 $ 194 $ 232
-------- ------- --------
Net Cash Flows From Operating Activities 2,308 2,067 2,818
Net Cash Flows Used For Investing Activities (1,888) (378) (3,292)
Net Cash Flows (Used For) From Financing Activities (437) (681) 437
Effect of Exchange Rate Changes on Cash - (3) (1)
-------- ------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (17) 1,005 (38)
-------- ------- --------
Cash and Cash Equivalents at End of Period $ 1,182 $1,199 $194
======== ======= ========
Cash from operations, combined with a bank-sponsored receivables purchase
agreement and short-term borrowings provide working capital and meet other
short-term cash needs. We use our corporate borrowing program to meet the
short-term borrowing needs of our subsidiaries. The corporate borrowing program
includes a utility money pool which funds the utility subsidiaries and a
non-utility money pool which funds the majority of the non-utility subsidiaries.
In addition, we also fund, as direct borrowers, the short-term debt requirements
of other subsidiaries that are not participants in the non-utility money pool
for regulatory or operational reasons. As of December 31, 2003, we had credit
facilities totaling $2.9 billion to support our commercial paper program. We
generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding mechanisms are arranged.
Sources of long-term funding include issuance of common stock, preferred stock
or long-term debt and sale-leaseback or leasing agreements. Money pool and
external borrowings may not exceed SEC authorized limits.
Operating Activities
- --------------------
2003 2002 2001
---- ---- ----
(in millions)
Net Income (Loss) $ 110 $ (519) $ 971
Plus: Discontinued Operations 605 654 (41)
------- ------- -------
Income from Continuing Operations 715 135 930
Noncash Items Included in Earnings 1,798 2,734 976
Changes in Assets and Liabilities (205) (802) 912
------- ------- -------
Net Cash Flows From Operating Activities $2,308 $2,067 $2,818
======= ======= =======
2003 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $2.3 billion for 2003. We produced
income from continuing operations of $715 million during the period. Income from
continuing operations for 2003 included noncash items of $1.5 billion for
depreciation, amortization, and deferred taxes, $193 million for the cumulative
effects of accounting changes, and $720 million for impairment losses and other
related charges. In addition, there is a current period impact for a net $122
million balance sheet change for risk management contracts that are
marked-to-market. These contracts have an unrealized earnings impact as market
prices move, and a cash impact upon settlement or upon disbursement or receipt
of premiums. Changes in Assets and Liabilities represent those items that had a
current period cash flow impact, such as changes in working capital, as well as
items that represent future rights or obligations to receive or pay cash, such
as regulatory assets and liabilities. The current period activity in these asset
and liability accounts relates to a number of items; the most significant are
presented below:
. The wholesale capacity auction true-up (ECOM) resulted in stranded cost
deferrals of $218 million, which are not recoverable in cash until the
conclusion of our Texas true-up proceeding. These proceedings are not
expected to be finalized earlier than April 2005.
. Net changes in accounts receivable and accounts payable of $269 million
related, in large part, to the settlement of risk management positions
during 2002 and payments related to those settlements during 2003. These
payments include $90 million in settlement of power and gas transactions
to the Williams Companies. The earnings effects of substantially all
payments were reflected in earlier periods.
. Increases in inventory levels of $71 million resulting primarily from
higher procurement prices.
. Reserves for disallowed fuel costs, principally related to Texas, which
will be a component of our 2004 final Texas true-up order of the PUCT.
2002 Operating Cash Flow
- ------------------------
During 2002, our cash flows from operating activities were $2.1 billion. Income
from continuing operations was $135 million during the period. Income from
continuing operations for 2002 included noncash items of $1.4 billion for
depreciation, amortization, and deferred taxes, $350 million related to the
cumulative effect of an accounting change, and $639 million for impairment
losses. There was a current period impact for a net $275 million balance sheet
change for risk management contracts that were marked-to-market. These contracts
have an unrealized earnings impact as market prices move, and a cash impact upon
settlement or upon disbursement or receipt of premiums. The activity in the
asset and liability accounts related to the wholesale capacity auction true-up
asset (ECOM) of $262 million, deposits associated with risk management
activities of $136 million, and seasonal increases in our fuel inventories.
2001 Operating Cash Flow
- ------------------------
Our cash flows from operating activities were $2.8 billion for 2001. Income from
continuing operations was $930 million during the period. Income from continuing
operations for 2001 included noncash items of $1.5 billion for depreciation,
amortization, and deferred taxes, and $18 million related to the cumulative
effect of an accounting change. There was a current period impact for a net $294
million balance sheet change for risk management contracts that were
marked-to-market. These contracts have an unrealized earnings impact as market
prices move, and a cash impact upon settlement or upon disbursement or receipt
of premiums. The activity in the asset and liability accounts was primarily
attributable to increased levels of trading activities as compared to 2002 and
2003. During the fourth quarter of 2002 we exited trading that was not related
to the sale of power from our owned-generation.
Investing Activities
- --------------------
2003 2002 2001
---- ---- ----
(in millions)
Construction Expenditures $(1,358) $(1,685) $(1,646)
Business Acquisitions/Sales Proceeds, net 82 1,263 (621)
Other (612) 44 (1,025)
-------- -------- --------
Net Cash Flows Used for Investing Activities $(1,888) $ (378) $(3,292)
======== ======== ========
Our cash flows used for investing activities increased $1.5 billion in 2003 from
$378 million during the prior year. This increase was due to additional sales
proceeds in 2002 related to SEEBOARD, CitiPower, and the Texas REPs as well as
increased investments in our U.K. operations during 2003. These increases were
partially offset by a reduction of our capital expenditures in 2003 as compared
to 2002.
In 2002, our cash flows used for investing activities decreased $2.9 billion
from 2001. This decrease resulted from the HPL and UK acquisitions during 2001
as well as the net increase in proceeds received from asset sales during 2002.
We forecast $5.8 billion of construction expenditures for 2004-2006.
Financing Activities
- --------------------
2003 2002 2001
---- ---- ----
(in millions)
Issuances of Equity Securities (common stock/equity units) $1,142 $ 990 $ 11
Issuances/Retirements of Debt, net (727) (868) 460
Retirement of Preferred Stock (9) (10) (5)
Issuance/Retirement of Minority Interest (225) - 744
Dividends (618) (793) (773)
------- ------ ------
Net Cash Flows (Used for) From Financing Activities $ (437) $(681) $ 437
======= ====== ======
Our cash flows used for financing activities decreased $244 million in 2003 from
$681 million during the prior year. This decrease was due to additional proceeds
from the issuance of common stock and the reduction of our common stock dividend
in 2003.
In 2002 we used $681 million for financing activities compared to $437 million
provided by the same activities in 2001. The increase in cash used pertained
primarily to the debt retirements that occurred in 2002.
The following financing activities occurred during 2003 and 2002:
Common Stock and Equity Units:
-----------------------------
. In March 2003, we issued 56 million shares of common stock at $20.95 per
share through an equity offering and received net proceeds of $1.1
billion (net of issuance costs of $36 million). We used the proceeds to
pay down both short-term and long-term debt with the balance being held
in cash.
. In June 2002, we issued 16 million shares of common stock at $40.90 per
share and 6.9 million equity units at $50 per unit and received combined
net proceeds of $979 million. We used the proceeds to pay down
short-term debt and establish a cash liquidity reserve fund.
Debt:
----
. We use our corporate borrowing program to meet the short-term borrowing
needs of our subsidiaries. The corporate borrowing program includes a
utility money pool which funds the utility subsidiaries and a
non-utility money pool which funds the majority of the non-utility
subsidiaries. In addition, we also fund, as direct borrowers, the
short-term debt requirements of other subsidiaries that are not
participants in the non-utility money pool for regulatory or operational
reasons. As of December 31, 2003, we had credit facilities totaling $2.9
billion to support our commercial paper program. At December 31, 2003,
we had $282 million outstanding in short-term borrowings supported by
these credit facilities. In addition, JMG has commercial paper
outstanding in the amount of $26 million. This commercial paper is
specifically associated with the Gavin scrubber lease. This commercial
paper does not reduce available liquidity.
. In February 2003, we issued over $2 billion of senior notes through our
Ohio and Texas subsidiaries. The proceeds were used to repay the bank
facility that was due to mature in April 2003, retire short-term debt
and for other general corporate purposes. During the remainder of the
year, our subsidiaries issued an additional $2.3 billion in senior notes
and refinanced approximately $465 million in pollution control revenue
bonds. The proceeds of these issuances were used to term-out short-term
debt, fund long-term debt maturities and fund optional redemptions.
. In March 2003, AEP issued a $500 million senior unsecured note. The
proceeds of this issuance were used to pay-down $225 million of the
Steelhead financing and to prefund a portion of the AEP Resources bond
that matured in December 2003.
. In May 2003, a third party exercised its option to call our $250 million
of 5.50% putable callable notes, issued in May 2001, for purchase and
remarketing. On May 15, 2003, AEP issued $300 million of 5.25% senior
notes due 2015, a portion of which was an exchange for the $250 million
putable callable notes due in 2003 that were outstanding at that time.
. AEP Credit extended its sale of receivables agreement from its May 28,
2003 expiration to July 25, 2003, when the agreement was renewed for an
additional 364 days. The sale of receivables agreement, which expires on
July 23, 2004, provides commitments of $600 million to purchase
receivables from AEP Credit. At December 31, 2003, $385 million of
commitments to purchase accounts receivable were outstanding under the
receivables agreement. All receivables sold represent affiliate
receivables. AEP Credit maintains a retained interest in the receivables
sold and this interest is pledged as collateral for the collection of
receivables sold. The fair value of the retained interest is based on
book value due to the short-term nature of the accounts receivable less
an allowance for anticipated uncollectible accounts.
. In September 2003, we closed on a $200 million revolving loan and letter
of credit facility. The facility is available for the issuance of
letters of credit and for general corporate purposes. The facility will
expire in September 2006.
Minority Interest and Off-balance Sheet Arrangements
- ----------------------------------------------------
We enter into minority interest and off-balance sheet arrangements for various
reasons including accelerating cash collections, reducing operational expenses
and spreading risk of loss to third parties. The following identifies
significant minority interest and off-balance sheet arrangements:
Minority Interest in Finance Subsidiary
- ---------------------------------------
We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis
Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated
subsidiary that was capitalized with the assets of Houston Pipe Line Company and
Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas
Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of
SubOne) preferred stock, that was convertible into our 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 for a managing member interest and $750 million from
Steelhead Investors LLC (Steelhead) for a non-controlling preferred member
interest. SubOne is the managing member of Caddis. As a result SubOne and all of
its subsidiaries, including Caddis, HPL and LIG, are included in our
Consolidated financial statements.
Steelhead is an unconsolidated special purpose entity and had an original
capital structure of $750 million (currently approximately $525 million) of
which 3% is equity from investors with no relationship to us or any of our
subsidiaries and 97% is debt from a syndicate of banks. The $525 million
invested in Caddis by Steelhead was loaned to SubOne. The loan to SubOne is due
August 2006. Net proceeds from the planned sale of LIG will be used to reduce
the outstanding balance of the loan from Caddis.
On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis,
which included amounts previously reported as Minority Interest in Finance
Subsidiary ($759 million at December 31, 2002 and $533 million at June 30,
2003). As a result, a $527 million note payable to Caddis is part of our
Long-Term Debt at December 31, 2003. Application of FIN 46 is prospective and
we, therefore, did not change the presentation of Minority Interest in Finance
Subsidiary in periods prior to July 1, 2003.
On May 9, 2003, we reduced the outstanding balance of our note payable to Caddis
by $225 million. Caddis used these proceeds to reduce the preferred interest in
Caddis that was held by Steelhead. This payment eliminated the convertible
preferred stock of AEP Gas Holding which under certain conditions had been
convertible to AEP stock.
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,
2003, SubOne has complied with the covenants contained in the credit agreement.
In addition, the acceleration of our outstanding debt in excess of $50 million
would be an event of default under the credit agreement.
SubOne has deposited $422 million in a cash reserve fund in order to comply with
certain covenants in the credit agreement. Pursuant to the terms of the credit
agreement, SubOne subsequently loaned these funds to affiliates, and we
guaranteed the repayment obligations of these affiliates. These loans must be
repaid in the event our credit ratings fall below investment grade.
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. Liquidation of Caddis could negatively impact our
liquidity.
AEP Credit
- ----------
AEP Credit has a sale of receivables agreement with banks and commercial paper
conduits. Under the sale of receivables agreement, 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.
AEP Credit extended its sale of receivables agreement to July 25, 2003 from its
May 28, 2003 expiration date. The agreement was then renewed for an additional
364 days and now expires on July 23, 2004. This new agreement provides
commitments of $600 million to purchase receivables from AEP Credit. At December
31, 2003, $385 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. 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.
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). The 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 certain institutional
investors. The future minimum lease payments for each respective company are
$1.4 billion.
The FASB and other accounting constituencies continue to interpret the
application of FIN 46 (revised December 2003) (FIN 46R). As a result, we are
continuing to review the application of this new interpretation as it relates to
the Rockport Unit 2 transaction.
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. Neither
AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of
these entities guarantee its debt.
Railcars
- --------
In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years. We intend to renew the lease for
the full twenty years.
At the end of each lease term, we may (a) renew for another five-year term, not
to exceed a total of twenty years, (b) purchase the railcars for the purchase
price amount specified in the lease, projected at the lease inception to be the
then fair market value, or (c) return the railcars and arrange a third party
sale (return-and-sale option). The lease is accounted for as an operating lease
with the future payment obligations included in the annual lease footnote. This
operating lease agreement allows us to avoid a large initial capital
expenditure, and to spread our railcar costs evenly over the expected
twenty-year usage.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under
the return-and-sale option discussed above will equal at least a lessee
obligation amount specified in the lease, which declines over time from
approximately 86% to 77% of the projected fair market value of the equipment. At
December 31, 2003, the maximum potential loss was approximately $31.5 million
($20.5 million net of tax) assuming the fair market value of the equipment is
zero at the end of the current lease term. The railcars are subleased for one
year to an unaffiliated company under an operating lease. The sublessee may
renew the lease for up to four additional one-year terms. AEP has other railcar
lease arrangements that do not utilize this type of financing structure.
Summary Obligation Information
- ------------------------------
Our contractual obligations include amounts reported on the Consolidated Balance
Sheets and other obligations disclosed in the footnotes. The following table
summarizes our contractual cash obligations at December 31, 2003:
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 $1,779 $3,460 $1,711 $7,151 $14,101
Short-term Debt 326 - - - 326
Preferred Stock Subject to
Mandatory Redemption - - 21 55 76
Capital Lease Obligations 63 77 49 31 220
Unconditional Purchase
Obligations (a) 1,720 2,132 1,101 1,785 6,738
Noncancellable Operating Leases 291 492 441 2,331 3,555
------- ------- ------- -------- --------
Total $4,179 $6,161 $3,323 $11,353 $25,016
======= ======= ======= ======== ========
(a) Represents contractual obligations to purchase coal and natural gas as
fuel for electric generation along with related transportation of the
fuel.
Some of the transactions, described under "Minority Interest and Off-Balance
Sheet Arrangements" above, include contractual cash obligations reported in the
above table. The lease of Rockport Unit 2 and Railcars are reported in
Noncancellable Operating Leases. The Minority Interest in Finance Subsidiary is
reported in Long-term Debt.
In addition to the amounts disclosed in the contractual cash obligations table
above, we make additional 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. Our commitments outstanding
at December 31, 2003 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) $ 175 $ 43 $ - $ 9 $ 227
Guarantees of the Performance of
Outside Parties (b) - 18 1 134 153
Guarantees of our Performance 1,083 107 - 8 1,198
Transmission Facilities for
Third Parties (c) 99 110 54 - 263
Other Commercial
Commitments (d) 14 14 - - 28
------- ----- ---- ----- -------
Total Commercial Commitments $1,371 $292 $55 $151 $1,869
======= ===== ==== ===== =======
(a) We have issued standby letters of credit to third parties. These letters
of credit cover gas and electricity risk management contracts,
construction contracts, insurance programs, security deposits, debt
service reserves and credit enhancements for issued bonds. All of these
letters of credit were issued in the ordinary course of business. The
maximum future payments of these letters of credit are $227 million with
maturities ranging from January 2004 to January 2011. As the parent of all
of these subsidiaries, we hold all assets of the subsidiaries 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 8.
(c) As construction agent for third party owners of transmission facilities,
we have committed by contract terms to complete construction by dates
specified in the contracts. Should we default on these obligations,
financial payments could be required including liquidating damages of up
to $8 million and other remedies required by contract terms.
(d) 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.
Expenditures for domestic electric utility construction are estimated to be $5.8
billion for the next three years. Approximately 80% of those construction
expenditures is expected to be financed by internally generated funds.
Other
- -----
Power Generation Facility
- -------------------------
We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Construction of the Facility was begun by Katco Funding, Limited Partnership
(Katco), an unrelated unconsolidated special purpose entity. Katco assigned its
interest in the Facility to Juniper in June 2003.
Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after
construction is completed.
At December 31, 2002, we would have reported the Facility and related
obligations as an operating lease upon achieving commercial operation (COD). In
the fourth quarter of 2003, we chose to not seek funding from Juniper for
budgeted and approved pipeline construction costs related to the Facility. In
order to continue reporting the Facility as an off-balance sheet financing, we
were required to seek funding of our construction costs from Juniper. As a
result, we recorded $496 million of construction work in progress (CWIP) and the
related financing liability for the debt and equity as of December 31, 2003. At
December 31, 2003, the lease of the Facility is reported as an owned asset under
a lease financing transaction. Since the debt obligations of the Facility are
recorded on our financial statements, the obligations under the lease agreement
are excluded from the above table of future minimum lease payments.
We are the construction agent for Juniper. We expect to achieve COD in the
spring of 2004, at which time the obligation to make payments under the lease
agreement will begin to accrue and we will sublease the Facility to The Dow
Chemical Company (Dow). If COD does not occur on or before March 14, 2004,
Juniper has the right to terminate the project. In the event the project is
terminated before COD, we have the option to either purchase the Facility for
100% of Juniper's acquisition cost (in general, the outstanding debt and equity
associated with the Facility) or terminate the project and make a payment to
Juniper for 89.9% of project costs (in general, the acquisition cost less
certain financing costs).
The initial term of the lease agreement between Juniper and AEP commences on COD
and continues for five years. The lease contains extension options, and if all
extension options are exercised, the total term of the lease will be 30 years.
AEP's lease payments to Juniper during the initial term and each extended term
are sufficient for Juniper to make required debt payments under Juniper's debt
financing associated with the Facility and provide a return on equity to the
investors in Juniper. We have the right to purchase the Facility for the
acquisition cost during the last month of the initial term or on any monthly
rent payment date during any extended term. In addition, we may purchase the
Facility from Juniper for the acquisition cost at any time during the initial
term if we have arranged a sale of the Facility to an unaffiliated third party.
A purchase of the Facility from Juniper by AEP should not alter Dow's rights to
lease the Facility or our contract to purchase energy from Dow. If the lease
were renewed for up to a 30-year lease term, we may further renew the lease at
fair market value subject to Juniper's approval, purchase the Facility at its
acquisition cost, or sell the Facility, on behalf of Juniper, to an independent
third party. If the Facility is sold and the proceeds from the sale are
insufficient to pay all of Juniper's acquisition costs, we may be required to
make a payment (not to exceed $396 million) to Juniper of the excess of
Juniper's acquisition costs over the proceeds from the sale, provided that we
would not be required to make any payment if we have made the additional rental
prepayment described below. We have guaranteed the performance of our
subsidiaries to Juniper during the lease term. Because we now report the debt
related to the Facility on our balance sheet, the fair value of the liability
for our guarantee (the $396 million payment discussed above) is not separately
reported.
At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496
million, and total costs for the completed Facility are currently expected to be
approximately $525 million. For the 30-year extended lease term, the base lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently,
as market interest rates increase, the base rental payments under the lease will
also increase. Annual payments of approximately $18 million represent future
minimum payments for interest on Juniper's financing structure during the
initial term calculated using the indexed LIBOR rate (1.15% at December 31,
2003). An additional rental prepayment (up to $396 million) may be due on June
30, 2004 unless Juniper has refinanced its present debt financing on a long-term
basis. Juniper is currently planning to refinance by June 30, 2004. The Facility
is collateral for the debt obligation of Juniper. At December 31, 2003, we
reflected $396 million of the $496 million recorded obligation as long-term debt
due within one year. Our maximum required cash payment as a result of our
financing transaction with Juniper is $396 million as well as interest payments
during the lease term. Due to the treatment of the Facility as a financing of an
owned asset, the recorded liability of $496 million is greater than our maximum
possible cash payment obligation to Juniper.
Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW
of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years
under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming.
On September 5, 2003, TEM and AEP separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. We
allege that TEM has breached the PPA, and we are seeking a determination of our
rights under the PPA. TEM alleges that the PPA never became enforceable, or
alternatively, that the PPA has already been terminated as the result of AEP
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, we could be adversely affected to the extent we are unable to find other
purchasers of the power with similar contractual terms to the extent we do not
fully recover claimed termination value damages from TEM. The corporate parent
of TEM has provided a limited guaranty.
On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM
basically argued that in the absence of mutually agreed upon protocols there was
no commercially reasonable means to obtain or deliver the electric power
products and therefore the PPA is not enforceable. TEM further argued that the
creation of the protocols is not subject to arbitration. The arbitrator ruled in
favor of TEM on February 11, 2004 and concluded that the "creation of protocols"
was not subject to arbitration, but did not rule upon the merits of TEM's claim
that the PPA is not enforceable.
If commercial operation is not achieved for purposes of the PPA by April 30,
2004, TEM may claim that it can terminate the PPA and is owed liquidating
damages of approximately $17.5 million. TEM may also claim that we are not
entitled to receive any termination value for the PPA.
The current litigation between TEM and ourselves, combined with a substantial
oversupply of generation capacity in the markets where we would otherwise sell
the power freed up by the TEM contract termination, triggered us to review the
project for possible impairment of its reported values. We determined that the
value of the Facility was impaired and recorded a $258 million pre-tax
impairment in December 2003 on the CWIP.
SIGNIFICANT FACTORS
- -------------------
Possible Divestitures
- ---------------------
We are firmly committed to continually evaluating the need to reallocate
resources to areas that effectively match our investments with our business
strategy, providing the greatest potential for financial returns. We are
committed to disposing of investments that no longer meet these goals.
We are seeking to divest significant components of our non-regulated assets,
including certain domestic and international unregulated generation, part of our
gas pipeline and storage business, a coal business, independent power producers
(IPPs) and a communications business. In June 2003, we began actively seeking
buyers for 4,497 megawatts of unregulated generating capacity in Texas. The
value received from this disposition will also be used to calculate our stranded
costs in Texas (see Note 6). We are currently evaluating bids received during
the fourth quarter of 2003 and are in negotiations to sell these assets.
During the second quarter of 2003, we also hired an advisor to evaluate our coal
business, which has resulted in the receipt of non-binding bids. We are
currently negotiating the anticipated sale of certain assets from this business.
In the fourth quarter of 2003, in connection with the evaluation of this
business, we recorded a $66.6 million pre-tax charge related to asset
impairments, remediation accruals and other exit costs (see Note 10).
During the third quarter of 2003, management hired advisors to review business
options regarding various investment components of our Gas Operations. We
distributed an initial offering memorandum and request for proposal on the sale
of our Louisiana Intrastate Gas and Jefferson Island Storage Facility operations
during the fourth quarter of 2003. We are currently evaluating the proposals
that we received. We are evaluating the merits of retaining our interest in
Houston Pipe Line, which is part of Gas Operations. In connection with our
review of the Gas Operations, we recorded $133.9 million in pre-tax charges
related to LIG and $315 million in pre-tax charges related to HPL (see Note 10).
We signed a sale agreement for the pipeline portion of LIG in the first quarter
of 2004 and we expect the sale to close shortly with an immaterial impact on
2004 results of operations.
During the third quarter of 2003, we initiated an effort to sell four domestic
IPP investments. Based on studies using current market assumptions, we believe
that two of the facilities had declines in fair value that are other than
temporary in nature. As a consequence, we recorded an impairment of $70 million
pre-tax ($45.5 million net of tax) in the third quarter of 2003 (see Note 10).
During the fourth quarter of 2003, we distributed an information memorandum
related to the possible sale of our interest in these IPPs. We have received and
are reviewing final bids and anticipate a sale of the four domestic IPP
investments in 2004.
During the fourth quarter of 2003, we engaged an advisor for the disposition of
our U.K. business and are planning to dispose of these assets in 2004. In
connection with the evaluation of this business, we recorded a pre-tax charge of
$577.4 million during the fourth quarter of 2003 based on indications of value
received from potential buyers (see Note 10).
Management continues to have periodic discussions with various parties on
business alternatives for certain of our other non-core investments.
The ultimate timing for a disposition of one or more of these assets will depend
upon market conditions and the value of any buyer's proposal. We may realize
losses from operations or upon disposition of these assets that, in the
aggregate, could have a material impact on our results of operations, cash flows
and financial condition.
Corporate Separation
- --------------------
In Texas, we are in the process of divesting our TCC generating assets in
accordance with provisions of the Texas Legislation concerning stranded cost
recovery (see Note 6). In order to sell these assets, we anticipate retiring
TCC's first mortgage bonds by making open market purchases or defeasing the
bonds. Once such generating assets are sold, which we expect to be finalized in
2004, we will effectively accomplish the structural separation requirements of
the Texas Legislation for those assets.
In Ohio, the PUCO has encouraged utilities to file rate stabilization plans to
provide rate certainty and stability for customers who do not choose alternative
suppliers, for the period of January 1, 2006 through December 31, 2008, which is
after the expiration of the current market development period. On February 9,
2004, CSPCo and OPCo filed such a rate stabilization plan with the PUCO. The
plan, in part, provides that both CSPCo and OPCo will remain functionally
separated. Approval of the rate stabilization plan is currently pending before
the PUCO.
Unless otherwise directed by the PUCO in an order on the rate stabilization
plan, CSPCo and OPCo will remain functionally separated through at least the end
of the rate stabilization plan period, December 31, 2008, and therefore, are not
planning to legally separate, or to change the affiliate pooling agreement for
the AEP East companies, in the foreseeable future.
Management continues to evaluate the most appropriate approach for complying
with the Texas Legislation's structural separation requirements for TNC,
including appropriate regulatory approvals to implement its structural
separation.
RTO Formation
- -------------
The FERC's AEP-CSW merger approval and many of the settlement agreements with
the state regulatory commissions to approve the AEP-CSW merger required the
transfer of functional control of our subsidiaries' transmission systems to
RTOs. Further, legislation in some of our states requires RTO participation.
In May 2002, we announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to be
negotiated. In July 2002, FERC issued an order accepting our decision to
participate in PJM, subject to specified conditions. AEP and other parties
continue to work on the resolution of those conditions.
In December 2002, our subsidiaries that operate in the states of Indiana,
Kentucky, Ohio and Virginia filed for state regulatory commission approval of
their plans to transfer functional control of their transmission assets to PJM.
Proceedings in Ohio remain pending.
In February 2003, the state of Virginia enacted legislation preventing APCo from
joining an RTO prior to July 1, 2004 and thereafter only with the approval of
the Virginia SCC, but required such transfers by January 1, 2005. In January
2004, APCo filed a cost/benefit study with the Virginia SCC covering the time
period through 2014 as required by the Virginia SCC. The study results show a
net benefit of approximately $98 million for APCo over the 11-year study period
from AEP's participation in PJM.
In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In December 2003,
AEP filed with the KPSC a cost/benefit study showing a net benefit of
approximately $13 million for KPCo over the five-year study period from AEP's
participation in PJM. A hearing has been scheduled in April 2004.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to certain
conditions included in the order. The IURC's order stated that AEP shall request
and the IURC shall complete a review of Alliance formation costs before any
deferral of the costs for future recovery.
In April 2003, FERC approved our transfer of functional control of the AEP East
companies' transmission system to PJM. FERC also accepted our proposed rates for
joining PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings. Settlement discussions continue on certain rate
matters.
On September 29 and 30, 2003, the FERC held a public inquiry regarding RTO
formation, including delays in AEP's participation in PJM. In November 2003, the
FERC issued an order preliminarily finding that AEP must fulfill its CSW merger
commitment to join an RTO by fully integrating into PJM (transmission and
markets) by October 1, 2004. The FERC set several issues for public hearing
before an ALJ. Those issues include whether the laws, rules, or regulations of
Virginia and Kentucky are preventing AEP from joining an RTO and whether the
states' provisions meet either of the two exceptions under PURPA. The FERC
directed the ALJ to issue his initial decision by March 15, 2004.
If AEP East companies do not obtain regulatory approval to join PJM, we are
committed to reimburse PJM for certain project implementation costs (presently
estimated at $24 million for AEP's share of the entire PJM integration project).
AEP also has $28 million, at December 31, 2003, of deferred RTO
formation/integration costs for which we plan to seek recovery in the future.
See Note 4 for further discussion.
AEP West companies are members of ERCOT or SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and SPP. State
public utility commissions also regulate our SPP companies. The Louisiana and
Arkansas commissions filed responses to the FERC's RTO order indicating that
additional analysis was required. Subsequently, the proposed SPP/MISO
combination was terminated. On October 15, 2003, SPP filed a proposal at FERC
for recognition as an RTO. In February 2004, FERC granted RTO status to the SPP,
subject to fulfilling specified requirements. Regulatory activities concerning
various RTO issues are ongoing in Arkansas and Louisiana.
Management is unable to predict the outcome of these regulatory actions and
proceedings or their impact on our transmission operations, results of
operations and cash flows or the timing and operation of RTOs.
Pension Plans
- -------------
We maintain qualified, defined benefit pension plans (Qualified Plans), which
cover a substantial majority of 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, we have entered into individual retirement agreements with certain
current and retired executives that provide additional retirement benefits.
Our net periodic pension expense was an income item for all pension plans
approximating $3 million and $44 million for the years ended December 31, 2003
and 2002, respectively, and is calculated based upon a number of actuarial
assumptions, including an expected long-term rate of return on the Qualified
Plans' assets. In 2002 and 2003, the long-term return was assumed to be 9.00%,
and for 2004, the long-term rate of return was lowered to 8.75%. In developing
the expected long-term rate of return assumption, we evaluated input from
actuaries and investment consultants, including their reviews of asset class
return expectations as well as long-term inflation assumptions. Projected
returns by such actuaries and consultants are based on broad equity and bond
indices. We also considered historical returns of the investment markets as well
as our 10-year average return, for the period ended December 2003, of
approximately 10.0%. We anticipate that the investment managers we employ for
the pension fund will continue to generate long-term returns of at least 8.75%.
The expected long-term rate of return on the Qualified Plan's assets is based on
our targeted asset allocation and our expected investment returns for each
investment category. Our assumptions are summarized in the following table:
2003 2004 Assumed/Expected
Actual Target Long-term Rate
Asset Allocation Asset Allocation of Return
---------------- ---------------- ----------------
(in percentage)
Equity 71 70 10.5
Fixed Income 27 28 5
Cash and Cash Equivalents 2 2 2
---- ----
Total 100 100
==== ====
Overall Expected Return (weighted average) 8.75
====
We regularly review the actual asset allocation and periodically rebalance the
investments to our targeted allocation when considered appropriate. We believe
that 8.75% is a reasonable long-term rate of return on the Qualified Plans'
assets despite the recent market volatility in which the Qualified Plans' assets
had a loss of 11.2% for the twelve months ended December 31, 2002, and a gain of
23.8% for the twelve months ended December 31, 2003. We will continue to
evaluate the actuarial assumptions, including the expected rate of return, at
least annually, and will adjust them 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, 2003, we had
cumulative losses of approximately $325 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 the 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 6.75% at December 31, 2002, to 6.25% at December 31, 2003.
Due to the effect of the unrecognized actuarial losses and based on an expected
rate of return on the Qualified Plans' assets of 8.75%, a discount rate of 6.25%
and various other assumptions, we estimate that the pension expense for all
pension plans will approximate $41 million, $78 million and $103 million in
2004, 2005 and 2006, respectively. Future actual pension cost will depend on
future investment performance, changes in future discount rates and various
other factors related to the populations participating in the pension plans.
Lowering the expected long-term rate of return on the Qualified Plans' assets by
0.5% (from 9.0% to 8.5%) would have increased pension cost for 2003 by
approximately $18 million (income of $3 million would have become $15 million in
pension expense). Lowering the discount rate by 0.5% would have reduced pension
income for 2003 by approximately $0.5 million.
The value of the Qualified Plans' assets has increased from $2.795 billion at
December 31, 2002 to $3.180 billion at December 31, 2003. The Qualified Plans
paid out $292 million in benefits to plan participants during 2003 (the
nonqualified plans paid out $7 million in benefits). Our plans remain in an
underfunded position (plan assets are less than projected benefit obligations)
of $508 million at December 31, 2003. Due to the pension plans currently being
underfunded, we recorded a charge to Other Comprehensive Income (OCI) of $585
million in 2002, and recorded a Deferred Income Tax Asset of $315 million,
offset by a Minimum Pension Liability of $662 million and a reduction to prepaid
costs and adjustment for unrecognized costs of $238 million. In 2003, the income
recorded in OCI was $154 million, and the reduction in the Deferred Income Tax
Asset was $76 million, offset by a reduction in Minimum Pension Liability of
$234 million and a reduction to adjustment for unrecognized costs of $4 million.
The charge to OCI does not affect earnings or cash flow. Due to the current
underfunded status of the Qualified Plans, we expect to make cash contributions
to the pension plans of approximately $41 million in 2004.
Certain of the defined benefit pension plans we sponsor and maintain contain a
cash balance benefit feature. In recent years, cash balance benefit features
have become a focus of scrutiny, as government regulators and courts consider
how the Employee Retirement Income Security Act of 1974, as amended, the Age
Discrimination in Employment Act, as amended, and other relevant federal
employment laws apply to plans with such a cash balance plan feature. We believe
that the defined benefit pension plans we sponsor and maintain are in
substantial compliance with the applicable requirements of such laws.
Nuclear Plant Outages
- ---------------------
In April 2003, engineers at STP, during inspections conducted regularly as part
of refueling outages, found wall cracks in two bottom mounted instrument guide
tubes of STP Unit 1. These tubes were repaired and the unit returned to service
in August 2003. Our share of the cost of repair for this outage was
approximately $6 million. We had commitments to provide power to customers
during the outage. Therefore, we were subject to fluctuations in the market
prices of electricity and purchased replacement energy.
In April 2003, both units of Cook Plant were taken offline due to an influx of
fish in the plant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of damage caused by the fish
intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to
service in June following completion of a scheduled refueling outage.
Litigation
- ----------
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
See discussion of the Federal EPA Complaint and Notice of Violation within
"Significant Factors - Environmental Matters."
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, certain subsidiaries of 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 from Enron 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
facility and the appurtenant pipelines. We have engaged in discussions with
Enron concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between AEP and
Enron relating to our acquisition of HPL and the possible resolution of
outstanding energy trading issues. We have considered the possible outcomes of
these issues in our impairment analysis of HPL; however, actual results could
differ from those estimates. We are unable to predict whether these discussions
will lead to an agreement on these subjects. In January 2004, AEP and its
subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the
U.S. Bankruptcy Court claiming that Enron does not have the right to reject the
Bammel storage facility agreement or the cushion gas use agreement, described
below. In February 2004 Enron filed Notices of Rejection regarding the cushion
gas use agreement and other incidental agreements. We have objected to Enron's
attempted rejection of these agreements. Management is unable to predict the
outcome of these proceedings or the impact on results of operations, cash flows
or financial condition.
We also entered into an agreement with BAM Lease Company which grants HPL the
exclusive right to use approximately 65 billion cubic feet of cushion gas
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust (owned by Enron and Bank of America (BOA)) purports to have a lien on
55 billion cubic feet of this cushion gas. These banks claim to have certain
rights to the cushion gas in certain events of default. In connection with our
acquisition of HPL, the banks and Enron entered into an agreement granting HPL's
exclusive use of 65 billion cubic feet of cushion gas. Enron and the banks
released HPL from all prior and future liabilities and obligations in connection
with the financing arrangement. After the Enron bankruptcy, HPL was informed by
the banks of a purported default by Enron under the terms of the financing
arrangement. In July 2002, the banks filed a lawsuit against HPL in the state
court of Texas seeking a declaratory judgment that they have a valid and
enforceable security interest in gas purportedly in the Bammel storage facility
which would permit them to cause the withdrawal of up to 55 billion cubic feet
of gas from the storage facility. In September 2002, HPL filed a general denial
and certain counterclaims against the banks including that Enron was a necessary
and indispensable party to the Texas state court proceeding initiated by BOA.
HPL also filed a motion to dismiss, which was denied. In December 2003, the
Texas state court granted partial summary judgment in favor of the banks. HPL
appealed this decision. We have considered the possible outcomes of these issues
in our impairment analysis of HPL; however, actual results could differ from
those estimates. Management is unable to predict the outcome of this lawsuit or
its impact on results of operations, cash flows and financial condition.
In October 2003, AEP Energy Services Gas Holding Company filed a lawsuit against
BOA in the United States District Court for the Southern District of Texas. On
January 8, 2004, this lawsuit was amended and seeks damages for BOA's breach of
contract, negligent misrepresentation and fraud in connection with transactions
surrounding our acquisition of HPL from Enron including entering into the Bammel
storage facility lease arrangement with Enron and the cushion gas arrangements
with BOA and Enron. BOA led a lending syndicate involving the 1997 gas
monetization that Enron and its subsidiaries undertook and the leasing of the
Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA
made misrepresentations and engaged in fraud to induce and promote the stock
sale of HPL, that BOA directly benefited from the sale of HPL and that AEP
undertook the stock purchase and entered into the Bammel storage facility lease
arrangement with Enron and the cushion gas arrangement with Enron and BOA based
on misrepresentations that BOA made about Enron's financial condition that BOA
knew or should have known were false including that the 1997 gas monetization
did not contravene or constitute a default of any federal, state, or local
statute, rule, regulation, code or any law.
In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related collateral
across various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas related trading transactions. We will
assert our right to offset trading payables owed to various Enron entities
against trading receivables due to several AEP subsidiaries. Management is
unable to predict the outcome of this lawsuit or its impact on our results of
operations, cash flows or financial condition.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. Management is unable to predict the
outcome of this lawsuit or its impact on our results of operations, cash flows
or financial condition.
During 2002 and 2001, we expensed a total of $53 million ($34 million net of
tax) for our estimated loss from the Enron bankruptcy. The amount expensed was
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. As noted above, Enron has
challenged our offsetting of receivables and payables and the Bammel storage
facility lease agreement and cushion gas agreement. Management is unable to
predict the final resolution of these disputes, however the impact on results of
operations, cash flows and financial condition could be material.
Bank of Montreal Claim
- ----------------------
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit against BOM claiming BOM had acted contrary to the appropriate trading
contract and industry practice in terminating the contract and calculating
termination and liquidation amounts and that BOM had acknowledged just prior to
the termination and liquidation that it owed us approximately $68 million. We
are claiming that BOM owes us at least $45 million. 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.
Arbitration of Williams Claim
- -----------------------------
In 2002, we filed a 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.
AEP and Williams settled the dispute with AEP paying $90 million to Williams in
June 2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter had an immaterial
impact on results of operations and financial condition. See Note 7 for further
discussion.
Arbitration of PG&E Energy Trading, LLC Claim
- ---------------------------------------------
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11
million to PGET. The settlement amount approximated the amount payable that, in
the ordinary course of business, we recorded as part of our trading activity
using MTM accounting. As a result, the settlement payment did not have a
material impact on results of operations, cash flows or financial condition.
Energy Market Investigations
- ----------------------------
AEP and other energy market participants received data requests, subpoenas and
requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity
Futures Trading Commission (CFTC), the U.S. Department of Justice and the
California attorney general during 2002. Management responded to the inquiries
and provided the requested information and has continued to respond to
supplemental data requests in 2003 and 2004.
In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC seeking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. The case is in the initial pleading stage with our
response to the complaint currently due on May 18, 2004. Although management is
unable to predict the outcome of this case, we recorded a provision in 2003 and
the action is not expected to have a material effect on results of operations.
In January 2004, the CFTC issued a request for documents and other information
in connection with a CFTC investigation of activities affecting the price of
natural gas in the fall of 2003. We are responding to that request.
Management cannot predict what, if any further action, any of these governmental
agencies may take with respect to these matters.
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 us, certain
executives, members of the Board of Directors and certain investment banking
firms. We intend to vigorously defend against these actions. See Note 7 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 has been dismissed
from the case. See Note 7 for further discussion.
Cornerstone Lawsuit
- -------------------
In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Shortly thereafter, a similar action was filed in the same court against
eighteen companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. These cases
are in the initial pleading stage. Management believes that the cases are
without merit and intends to vigorously defend against them.
TEM Litigation
- --------------
See discussion of TEM litigation within the "Financial Condition - Other"
section of Management's Financial Discussion and Analysis.
Texas Commercial Energy, LLP Lawsuit
- ------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against us and
four AEP subsidiaries, certain unaffiliated energy companies and ERCOT alleging
violations of the Sherman Antitrust Act, fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, civil conspiracy and negligence.
The allegations, not all of which are made against the AEP companies, range from
anticompetitive bidding to withholding power. TCE alleges that these activities
resulted in price spikes requiring TCE to post additional collateral and
ultimately forced it into bankruptcy when it was unable to raise prices to its
customers due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary damages and
court costs. Management believes that the claims against us are without merit.
We intend to vigorously defend against the claims. See Note 7 for further
discussion.
COLI Litigation
- ---------------
A decision by the U.S. District Court for the Southern District of Ohio in
February 2001 that denied AEP's deduction of interest claimed on AEP's
consolidated federal income tax returns related to a COLI program resulted in a
$319 million reduction in AEP's Net Income for 2000. We filed an appeal of the
U.S. District Court's decision with the U.S. Court of Appeals for the 6th
Circuit. In April 2003, the Appeals Court ruled against AEP. The U.S. Supreme
Court has declined to hear this issue.
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 and paid $59 million to us. The settlement amount was
less than the amount receivable that, in the ordinary course of business, we
recorded using MTM accounting. As a result, we incurred a $10 million pre-tax
loss.
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 results of operations, cash flows or financial condition.
Potential Uninsured Losses
- --------------------------
Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including, but not limited to, liabilities relating to damage to
the Cook Plant or STP and costs of replacement power in the event of a nuclear
incident at the Cook Plant or STP. Future losses or liabilities which are not
completely insured, unless recovered from customers, could have a material
adverse effect on results of operations, cash flows and financial condition.
Environmental Matters
- ---------------------
There are new environmental control requirements that we expect will result in
substantial capital investments and operational costs. The sources of these
future requirements include:
. Legislative and regulatory proposals to adopt stringent controls on
sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from
coal-fired power plants,
. New Clean Water Act rules to reduce the impacts of water intake
structures on aquatic species at certain of our power plants, and
. Possible future requirements to reduce carbon dioxide emissions to
address concerns about global climatic change.
In addition to achieving full compliance with all applicable legal requirements,
we strive to go beyond compliance in an effort to be good environmental
stewards. For example, we invest in research, through groups like the Electric
Power Research Institute, to develop, implement and demonstrate new emission
control technologies. We plan 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 invested over $2 billion, from 1990 through 2003, to equip many
of our facilities with pollution control technologies. We will continue to
make investments to improve the air emissions from our generating stations
because this is the most cost effective generation source for our customers'
electricity needs.
The Current Air Quality Regulatory Framework
- --------------------------------------------
The Clean Air Act (CAA) is the legislation that establishes the federal
regulatory authority and oversight for emissions from our fossil-fired
generating plants. The states, with oversight and approval from the Federal EPA,
administer and enforce these laws and related regulations.
Title I of the CAA
- ------------------
National Ambient Air Quality Standards
- --------------------------------------
The Federal EPA periodically reviews the available scientific data for six
pollutants and establishes a standard for concentration levels in ambient air
for these substances to protect the public welfare and public health with an
extra margin for safety. These requirements are known as "national ambient air
quality standards" (NAAQS).
The states identify those areas within their state that meet the NAAQS
(attainment areas) and those that do not (non-attainment areas). States must
develop their individual state implementation plans (SIPs) with the intention of
bringing non-attainment areas into compliance with the NAAQS. In developing a
SIP each state must allow attainment areas to maintain compliance with the
NAAQS. This is accomplished by controlling sources that emit one or more
pollutants or precursors to those pollutants. The Federal EPA approves SIPs if
they meet the minimum criteria in the CAA. Alternatively, the Federal EPA may
prescribe a federal implementation plan if they conclude that a SIP is
deficient. Additionally, the Federal EPA can impose sanctions, up to and
including withholding of federal highway funds, in states that fail to submit an
adequate SIP or a SIP that fails to bring non-attainment areas into NAAQS
compliance within the time prescribed by the CAA.
The CAA also establishes visibility goals, which are known as the regional haze
program, for certain federally designated areas, including national parks.
States are required to develop and submit SIP provisions that will demonstrate
reasonable progress toward preventing the impairment and remedying any existing
impairment of visibility in these federally designated areas.
Each state's SIP must include requirements to control sources that emit
pollutants in that state as well as requirements to control sources that
significantly contribute to non-attainment areas in another state. If a state
believes that its air quality is impacted by upwind sources outside their
borders, that state can submit a petition that asks the Federal EPA to impose
control requirements on specific sources in other states if those states' SIPs
do not contain adequate requirements to control those sources. For example, the
Federal EPA issued a NOx Rule in 1997, which affected 22 eastern states
(including states in which AEP operates) and the District of Columbia. The NOx
Rule asked these 23 jurisdictions to adopt requirements, for utility and
industrial boilers and certain other emission sources, to employ cost-effective
control technologies to reduce NOx emissions. The purpose of the request was to
allow certain eastern states to reduce the contribution from these 23
jurisdictions to ozone non-attainment areas in certain eastern states.
The Federal EPA also granted four petitions filed by certain eastern states
seeking essentially the same levels of control on emission sources outside of
their states and issued a Section 126 Rule. All of the states in which we
operate that were subject to the NOx Rule have submitted the required SIP
revisions. In response, the Federal EPA issued the NOx Rule and the Section 126
Rule, which are discussed below.
The compliance date for the NOx Rule is May 31, 2004. In 2000, the Federal EPA
also adopted a revised Section 126 Rule which granted petitions filed by four
northeastern states. The revised Section 126 Rule imposes emissions reduction
requirements comparable to the NOx Rule also beginning May 31, 2004, for most of
our coal-fired generating units.
In 2000, the Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including TCC and
SWEPCo. The compliance requirements began in May 2003 for TCC and begin in May
2005 for SWEPCo.
We are installing a variety of emission control technologies to improve NOx
emissions standards and to comply with applicable state and federal NOx
requirements. These include selective catalytic reduction (SCR) technology on
certain units and other combustion control technologies on a larger number of
units.
AEP's electric utility units are currently subject to SIP requirements that
control SO2 and particulate matter emissions in all states, and that control NOx
emissions in certain states. Our generating plants comply with applicable SIP
limits for SO2, NOx and particulate matter.
Hazardous Air Pollutants
- ------------------------
In 1990 Amendments to the CAA, Congress required the Federal EPA to identify the
sources of 188 hazardous air pollutants (HAPs) and to develop regulations that
prescribe a level of HAP emission reduction. These reductions must reflect the
application of maximum achievable control technology (MACT). Congress also
directed the Federal EPA to investigate HAP emissions from the electric utility
sector and to submit a report to Congress. The Federal EPA's 1998 report to
Congress identified mercury emissions from coal-fired electric utility units and
nickel emissions from oil-fired utility units as sources of HAP emissions that
warranted further investigation and possible control.
New Source Performance Standards and New Source Review
- ------------------------------------------------------
The Federal EPA establishes New Source Performance Standards (NSPS) for 28
categories of major stationary emission sources that reflect the best
demonstrated level of pollution control. Sources that are constructed or
modified after the effective date of an NSPS standard are required to meet those
limitations. For example, many electric utility units are regulated under the
NSPS for SO2, NOx, and particulate matter. Similarly, each SIP must include
regulations that require new sources, and major modifications at existing
emission sources that result in a significant net increase in emissions, to
submit a permit application and undergo a review of available technologies to
control emissions of pollutants. These rules are called new source review (NSR)
requirements.
Different NSR requirements apply in attainment and non-attainment areas.
In attainment areas:
. An air quality review must be performed, and
. The best available control technology must be employed to reduce new
emissions.
In non-attainment areas,
. Requirements reflecting the lowest achievable emission rate are applied
to new or modified sources, and
. All new emissions must be offset by reductions in emissions of the same
pollutant from other sources within the same control area.
Neither the NSPS nor NSR requirements apply to certain activities, including
routine maintenance, repair or replacement, changes in fuels or raw materials
that a source is capable of accommodating, the installation of a pollution
control project, and other specifically excluded activities.
Title IV of the CAA (Acid Rain)
- -------------------------------
The 1990 Amendments to the CAA included a market-based emission reduction
program designed to reduce the amount of SO2 emitted from electric utility units
by approximately 50 percent from 1980 levels. This program also established a
nationwide cap on utility SO2 emissions of 8.9 million tons per year. The
Federal EPA administers its SO2 program through an allowance allocation and
trading system. Allowances are allocated to specific units based on statutory
formulas. Annually each utility unit must surrender one allowance for each ton
of SO2 that it emits. Emission sources that install controls and no longer need
all of their allowances can bank those allowances for future use or trade them
to other emission sources.
Title IV also contains requirements for utility sources to reduce NOx emissions
through the use of available combustion controls. Units must meet NOx emission
rates standards which are specific to that unit or units may participate in an
annual averaging program for utility units that are under common control.
Future Reduction Requirements for SO2, NOx, and Mercury
- -------------------------------------------------------
In 1997, the Federal EPA adopted new, more stringent NAAQS for fine particulate
matter and ground-level ozone. The Federal EPA is in the process of developing
final designations for fine particulate matter and ground-level ozone
non-attainment areas. The Federal EPA has identified SO2 and NOx emissions as
precursors to the formation of fine particulate matter. NOx emissions are also
identified as a precursor to the formation of ground-level ozone. As a result,
requirements for future reductions in emissions of NOx and SO2 from our
generating units are highly probable. In addition, the Federal EPA has proposed
a set of options for future mercury controls at coal-fired power plants.
Multi-emission control legislation, known as the Clear Skies Act, was introduced
in Congress and is supported by the Bush Administration. This legislation would
regulate NOx, SO2, and mercury emissions from electric generating plants. We
support enactment of this comprehensive, multi-emission legislation so that
compliance planning can be coordinated and collateral emission reductions
maximized. We believe the Bush Administration's Clear Skies Act would establish
stringent emission reduction targets and achievable compliance timetables
utilizing a cost-effective nationwide cap and trade program. Although the
prospects for enactment of the Clear Skies Act are low, there are alternative
regulatory approaches which will likely require us to substantially reduce SO2,
NOx and mercury emissions over the next ten years.
Regulatory Emissions Reductions
- -------------------------------
On January 30, 2004, the Federal EPA published two proposed rules that would
collectively require reductions of approximately 70% in emissions of SO2, NOx
and mercury from coal-fired electric generating units by 2015 (2018 for
mercury). This initiative has two major components:
. The Federal EPA proposed an interstate air quality rule for reducing SO2
and NOx emissions across the eastern half of the United States (29
states and the District of Columbia) to address attainment of the fine
particulate matter and ground-level ozone NAAQS. These reductions could
also satisfy these states' obligations to make reasonable progress
towards the national visibility goal under the regional haze program.
. The Federal EPA proposed to regulate mercury emissions from coal-fired
electric generating units.
The interstate air quality rule would require affected states to include, in
their SIPs, a program to reduce NOx and SO2 emissions from coal-fired electric
utility units. SO2 and NOx emissions would be reduced in two phases, which would
be implemented through a cap-and-trade program. Regional SO2 emissions would be
reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional
NOx emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million
tons by 2015. Rules to implement the SO2 and NOx trading programs have not yet
been proposed.
To control and reduce mercury emissions, the Federal EPA published two
alternative proposals. The first option requires the installation of MACT on a
site-specific basis. Mercury emissions would be reduced from 48 tons to
approximately 34 tons by 2008. The Federal EPA believes, and the industry
concurs, that there are no commercially available mercury control technologies
in the marketplace today that can achieve the MACT standards for bituminous
coals, but certain units have achieved comparable levels of mercury reduction by
installing conventional SO2 (scrubbers) and NOx (SCR) emission reduction
technologies. The proposed rule imposes significantly less stringent standards
on generating plants that burn sub-bituminous coal or lignite, which standards
potentially could be met without installation of mercury control technologies.
The Federal EPA recommends, and we support, a second mercury emission reduction
option. The second option would permit mercury emission reductions to be
achieved from existing sources through a national cap-and-trade approach. The
cap-and-trade approach would include a two-phase mercury reduction program for
coal-fired utilities. This approach would coordinate the reduction requirements
for mercury with the SO2 and NOx reduction requirements imposed on the same
sources under the proposed interstate air quality rule. Coordination is
significantly more cost-effective because technologies like scrubbers and SCRs,
that can be used to comply with the more stringent SO2 and NOx requirements,
have also proven highly effective in reducing mercury emissions on certain
coal-fired units that burn bituminous coal. The second option contemplates
reducing mercury emissions from 48 million tons to 34 million tons by 2010 and
to 15 million tons by 2018.
The Federal EPA's proposals are the beginning of a lengthy rulemaking process,
which will involve supplemental proposals on many details of the new regulatory
programs, written comments and public hearings, issuance of final rules, and
potential litigation. In addition, states have substantial discretion in
developing their rules to implement cap-and-trade programs, and will have 18
months after publication of the notice of final rulemaking to submit their
revised SIPs. As a result, the ultimate requirements may not be known for
several years and may depart significantly from the original proposed rules
described here.
While uncertainty remains as to whether future emission reduction requirements
will result from new legislation or regulation, it is certain under either
outcome that we will invest in additional conventional pollution control
technology on a major portion of our fleet of coal-fired power plants.
Finalization of new requirements for further SO2, NOx and/or mercury emission
reductions will result in the installation of additional scrubbers, SCR systems
and/or the installation of emerging technologies for mercury control.
Estimated Air Quality Environmental Investments
- -----------------------------------------------
Each of the current and possible future environmental compliance requirements
discussed above will require us to make significant additional investments, some
of which are estimable. The proposed rules discussed above have not been
adopted, will be subject to further revision, and will be the subject of a court
challenge and further modifications.
All of our estimates are subject to significant uncertainties about the outcome
of several interrelated assumptions and variables, including:
. Timing of implementation
. Required levels of reductions
. Allocation requirements of the new rules, and
. Our selected compliance alternatives.
As a result, we cannot estimate our compliance costs with certainty, and the
actual costs to comply could differ significantly from the estimates discussed
below.
All of the costs discussed below are incremental to our current investment base
and operating cost structure. These expenditures for pollution control
technologies, replacement generation and associated operating costs are
recoverable from customers through regulated rates (in regulated jurisdictions)
and should be recoverable through market prices (in deregulated jurisdictions).
If not, those costs could adversely affect future results of operations and cash
flows, and possibly financial condition.
Estimated Investments for NOx Compliance
- ----------------------------------------
We estimate that we will make future investments of approximately $600 million
to comply with the Federal EPA's NOx Rule, the Texas Commission on Environmental
Quality Rule and other final Federal EPA NOx-related requirements. Approximately
$500 million of these investments are reflected in our estimated construction
expenditures for 2004 - 2006. As of December 31, 2003, we have invested
approximately $1.1 billion to comply with various NOx requirements.
Estimated Investments for SO2 Compliance
- ----------------------------------------
We are complying with Title IV SO2 requirements by installing scrubbers, other
controls and fuel switching at certain generating units. We also use SO2
allowances that we:
. Receive in the annual allowance allocation by the Federal EPA,
. Obtain through participation in the annual allowance auction,
. Purchase in the allowance market, and
. Obtained as bonus allowances for installing controls early.
Decreasing SO2 allowance allocations, a diminishing SO2 allowance bank, and
increasing allowance prices in the market will require us to install additional
controls on certain of our generating units. We plan to install 3,500 MW of
additional scrubbers over the next 4 years to comply with our Title IV SO2
obligations. In total we estimate these additional capital costs to be
approximately $1.2 billion. Of this total, we estimate that $900 million will be
expended during 2004-2006 and this amount is included in our total estimated
construction expenditures for 2004 - 2006.
Estimated Investments to Comply with Future Reduction Requirements
- ------------------------------------------------------------------
Our planning assumptions for the levels and timing of emissions reductions
parallel the reduction levels and implementation time periods stated in the
proposed rules issued by the Federal EPA in January 2004. We have also assumed
that the Federal EPA will implement a mercury trading option and will design its
proposed cap and trade mechanism for SO2, NOx and mercury emissions in a manner
similar to existing cap and trade programs. Based on these assumptions,
compliance would require additional capital investment of approximately $1.7
billion by 2010, the end of the first phase for each proposed rule. We also
estimate that we would incur increases in variable operation and maintenance
expenses of $150 million for the periods by 2010, due to the costs associated
with the maintenance of additional control systems, disposal of scrubber
by-products and the purchase of reagents. We estimate that we will invest $200
million of this amount through 2006, and this amount is included in our total
estimated construction expenditures for 2004 - 2006.
If the Federal EPA's preferred mercury trading option is not implemented, then
any alternative mercury control program requiring adherence to MACT standards
would also have implementation costs that could be significant. We cannot
currently estimate the nature or amount of these costs. Furthermore, scrubber
and SCR technologies could not be deployed at every bituminous-fired plant that
AEP operates within the three-year compliance schedule provided under the
proposed MACT rule. These MACT compliance costs, which we are not able to
estimate, would be incremental to other cost estimates that we have discussed
above.
Beyond 2010, we expect to incur additional costs for pollution control
technology retrofits and associated operation and maintenance of the equipment.
We cannot estimate these additional costs because of the uncertainties
associated with the final control requirements and our associated compliance
strategy, but these capital and operating costs will be significant.
New Source Review Litigation
- ----------------------------
Under the CAA, 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 Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints
against our subsidiaries in U.S. District Court for the Southern District of
Ohio. The court also consolidated a separate lawsuit, initiated by certain
special interest groups, with the Federal EPA case. The alleged modifications
relate to costs that were incurred at our generating units over a 20-year
period.
We are unable to estimate the loss or range of loss related to the contingent
liability for civil penalties under the CAA proceedings. We are also 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 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.
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.
Superfund addresses clean-up of hazardous substances at disposal sites and
authorized the Federal EPA to administer the clean-up programs. As of year-end
2003, subsidiaries of AEP are named by the Federal EPA as a PRP for five sites.
There are six additional sites for which our subsidiaries have received
information requests which could lead to PRP designation. Our subsidiaries have
also been named potentially liable at six sites under state law. 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 were
attributed to our subsidiaries in the future under Superfund, results of
operations, cash flows and possibly financial condition would be adversely
affected unless the costs can be included in our electricity prices.
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. The U.S. signed the Kyoto
Protocol on November 12, 1998, but 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. Ratification of the treaty by a majority
of the countries' legislative bodies is required for it to be enforceable.
Enforceability of the protocol is now contingent on ratification by Russia,
which has expressed concerns about doing so.
On August 28, 2003, the Federal EPA issued a decision in response to a petition
for rulemaking seeking reductions of CO2 and other greenhouse gas emissions from
mobile sources. The Federal EPA denied the petition and issued a memorandum
stating that it does not have the authority under the Clean Air Act to regulate
CO2 or other greenhouse gas emissions that may affect global warming trends. The
Circuit Court of Appeals for the District of Columbia is reviewing these
actions.
We do not support the Kyoto Protocol but have been working with the Bush
Administration on a voluntary program aimed at meeting the President's goal of
reducing the greenhouse gas intensity of the economy by 18% by 2012. For many
years, we have been a leader in pursuing voluntary actions to control greenhouse
gas emissions. We expanded our commitment in this area in 2002 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.
We acquired 4,000 MW of coal-fired generation in the United Kingdom in December
2001. These assets may have future CO2 emission control obligations beginning in
2005. We plan to dispose of our investment in this generation during 2004.
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 to
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 7. Since 1983 I&M has collected
$316 million from customers for the disposal of nuclear fuel consumed at the
Cook Plant. We deposited $117 million of these funds in external trust funds to
provide for the future disposal of SNF and remitted $199 million to the DOE. TCC
has collected and remitted to the DOE, $56 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
with a trial scheduled in March 2004. 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.
The cost to decommission nuclear plants is affected by both NRC regulations and
the delayed SNF disposal program. Studies completed in 2003 estimate the cost to
decommission the Cook Plant ranges from $821 million to $1.08 billion in 2003
non-discounted dollars. External trust funds have been established with amounts
collected from customers to decommission the plant. At December 31, 2003, the
total decommissioning trust fund balance for Cook Plant was $720 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, 2003, the total
decommissioning trust fund for TCC's share of STP was $125 million which
includes earnings on the trust investments. Estimates from the decommissioning
studies could continue to escalate due to the uncertainty in the SNF disposal
program and the length of time that SNF may need to be stored at the plant site.
I&M and TCC will work with regulators and customers to recover the remaining
estimated costs of decommissioning Cook Plant and STP. However, our future
results of operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning continues to
increase and cannot be recovered.
Clean Water Act Regulation
- --------------------------
On February 16, 2004, the Federal EPA signed a rule pursuant to the Clean Water
Act that will require all large existing power plants to meet certain
performance standards to reduce the mortality of juvenile and adult fish or
other larger organisms pinned against a plant's cooling water intake screens. A
subset of these plants that are located on sensitive water bodies will be
required to meet additional performance standards for reducing the number of
smaller organisms passing through the water screens and the cooling system.
Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and
small rivers with large plants. These rules will result in additional capital
and operation and maintenance expenses to ensure compliance.
Other Environmental Concerns
- ----------------------------
We perform environmental reviews and audits on a regular basis for the purpose
of identifying, evaluating and addressing environmental concerns and issues. In
addition to the matters discussed above we are managing other environmental
concerns which we do not believe are material or potentially material at this
time. If they become significant or if any new matters arise that we believe
could be material, they could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
Critical Accounting Policies
- ----------------------------
In the ordinary course of business, we use a number of estimates and assumptions
relating to the reporting of results of operations and financial condition in
the preparation of our financial statements in conformity with accounting
principles generally accepted in the United States of America, including amounts
related to legal matters and contingencies. Actual results can differ
significantly from those estimates under different assumptions and conditions.
We believe 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
- ---------------------
Our consolidated financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate-regulated. We recognize regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) for the economic effects of
regulation. Specifically, we match the timing of our expense recognition with
the recovery of such expense in regulated revenues. Likewise, we match income
with its passage to customers through regulated revenues in the same accounting
period. We also record regulatory liabilities for refunds, or probable 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 it is determined 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
- ------------------------------------------------------
We recognize revenues on the accrual or settlement basis for normal retail and
wholesale electricity supply sales and electricity transmission and distribution
delivery services. That is, we recognize and record revenues when the energy is
delivered to the customer and include estimated 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
- --------------------------------------------
We recognize revenues from domestic gas pipeline and storage services when gas
is delivered to contractual meter points or when services are provided, with the
exception of certain physical forward gas purchase and sale contracts that are
derivatives and are required to be accounted for using mark-to-market accounting
(Resale Gas Contracts).
Energy Marketing and Risk Management Activities
- -----------------------------------------------
We engage in wholesale electricity, natural gas and coal marketing and risk
management activities. Effective in October 2002, these activities were focused
on wholesale markets where we own assets. Our activities include 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. Prior to October
2002, we recorded wholesale marketing and risk management activities using the
mark-to-market method of accounting.
In October 2002, EITF 02-3 precluded mark-to-market accounting for risk
management contracts that were not derivatives pursuant to SFAS 133. We
implemented this standard for all non-derivative wholesale and risk management
transactions occurring on or after October 25, 2002. For non-derivative risk
management transactions entered into prior to October 25, 2002, we implemented
this standard on January 1, 2003 and reported the effects of implementation as a
cumulative effect of an accounting change.
After January 1, 2003, we use mark-to-market accounting for wholesale marketing
and risk management transactions that are derivatives unless the derivative is
designated for hedge accounting or the normal purchase and sale exemption.
Revenues and expenses are recognized from wholesale marketing and risk
management transactions that are not derivatives when the commodity is
delivered.
See discussion of EITF 02-3 and Rescission of EITF 98-10 in Note 2.
Accounting for Derivative Instruments
- -------------------------------------
For derivative contracts that are not designated as hedges or normal purchase
and sale transactions we recognize unrealized gains and losses prior to
settlement based on changes in fair value during the period in our results of
operations. When we settle mark-to-market derivative contracts and realize gains
and losses, we reverse previously recorded unrealized gains and losses from
mark-to-market valuations.
We designate certain derivative instruments as hedges of forecasted transactions
or future cash flows (cash flow hedges) or as a hedge of a recognized asset,
liability or firm commitment (fair value hedge). We report changes in the fair
value of these instruments on our balance sheet. We do not recognize changes in
the fair value of the derivative instrument designated as a hedge in the current
results of operations until earnings are impacted by the hedged item. We also
recognize any changes in the fair value of the hedging instrument that are not
offset by changes in the fair value of the hedged item immediately in earnings.
We measure the fair values of derivative instruments and hedge instruments
accounted for using mark-to-market accounting based on exchange prices and
broker quotes. If a quoted market price is not available, we estimate the fair
value based on the best information available including valuation models that
estimate future energy prices based on existing market and broker quotes, supply
and demand market data, and other assumptions. We reduce fair values by
estimated valuation adjustments for items such as discounting, liquidity and
credit quality. There are inherent risks related to the underlying assumptions
in models used to fair value open long-term derivative 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 a contract
settles. Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices are not consistent
with our approach at estimating current market consensus for forward prices in
the current period. This is particularly true for long-term contracts.
We recognize all derivative instruments at fair value in our Consolidated
Balance Sheets as either "Risk Management Assets" or "Risk Management
Liabilities." We do not consider contracts that have been elected normal
purchase or normal sale under SFAS 133 to be derivatives. Unrealized and
realized gains and losses on all derivative instruments are ultimately included
in Revenues in the Consolidated Statement of Operations on a net basis, with the
exception of physically settled Resale Gas Contracts for the purchase of natural
gas. The unrealized and realized gains and losses on these Resale Gas Contracts
are presented as Purchased Gas for Resale in the Consolidated Statement of
Operations.
Long-Lived Assets
- -----------------
Long-lived assets 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 carrying amount is not recoverable, an impairment
is recorded to the extent that the fair value of the asset is less than its book
value.
Pension Benefits
- ----------------
We sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors which attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants 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. See "Pension Plans" in Significant Factors section
of Management's Financial Discussion and Analysis.
New Accounting Pronouncements
- -----------------------------
Effective July 1, 2003, we implemented FIN 46, "Consolidation of Variable
Interest Entities." As a result of the implementation, we consolidated two
entities, Sabine Mining Company ($77.8 million) and JMG ($469.6 million), which
were previously off-balance sheet. These entities were consolidated with SWEPCo
and OPCo, respectively. There is no change in net income due to the
consolidations. In addition, we deconsolidated Cadis Partners, LLC and the
trusts which hold mandatorily redeemable trust preferred securities which were
previously reported as Minority Interest in Finance Subsidiary ($533 million)
and Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities
of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries ($321 million), respectively. As a result of the deconsolidation
these amounts are now included in Long-term Debt. In December 2003, the FASB
issued FIN 46R which replaces FIN 46. The FASB and other accounting
constituencies continue to interpret the application of FIN 46R. As a result, we
are continuing to review the application of this new interpretation and expect
to adopt FIN 46R by March 31, 2004.
See Notes 1 and 2 to the consolidated financial statements for a discussion of
significant accounting policies and additional impacts of new accounting
pronouncements.
Other Matters
- -------------
FERC Proposed Standard Market Design
- ------------------------------------
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, which sought to standardize the structure and operation of
wholesale electricity markets across the country. Key elements of FERC's
proposal included 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 issued a "white paper" on the proposal in April 2003, in
response to the numerous comments that the FERC received on its proposal.
Management does not know if or when the FERC will finalize a rule for SMD. Until
any potential rule is finalized, management cannot predict its effect on cash
flows and results of operations.
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. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Management is unable to predict the timing of any
further action by the FERC or its affect of future results of operations and
cash flows.
Seasonality
- -----------
The sale of electric power in our service territories 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
due to the nature and location of our facilities and the terms of power
contracts into which we enter. In addition, we have historically sold less
power, and consequently earned less income, when weather conditions are milder.
Unusually mild weather in the future could diminish our results of operations
and may impact cash flows and financial condition.
Non-Core Investments
- --------------------
Additional market deterioration associated with our non-core wholesale
investments (all operations outside our traditional domestic regulated utility
operations), including our U.K. operations, merchant generation facilities, and
certain gas storage and pipeline assets, could have an adverse impact on future
results of operations and cash flows. Further changes in external market
conditions could lead to additional write-offs and further divestitures of our
wholesale investments, including, but not limited to, the U.K. operations,
merchant generation facilities, and our gas storage and pipeline operations. See
Note 10 for additional information regarding assets and investments currently
recorded as held for sale.
Investments Limitations
- -----------------------
Our investment, including guarantees of debt, in certain types of activities is
limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling
securities in an amount up to 100% of our average quarterly consolidated
retained earnings balance for investment in EWGs and FUCOs. At December 31,
2003, our investment in EWGs and FUCOs was $1.7 billion, including guarantees of
debt, compared to our limit of $2.1 billion.
SEC Rule 58, under the general rules and regulations of the PUHCA, permits us to
invest up to 15% of consolidated capitalization (such amount was $3.4 billion at
December 31, 2003) in energy-related companies, including marketing and/or risk
management activities in electricity, gas and other energy commodities. As of
December 31, 2003 AEP has invested $2.8 billion in these energy-related
companies.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
- -------------------------------------------------------------------------
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.
We have established policies and procedures which allow us to identify, assess,
and manage market risk exposures in our day-to-day operations. Our risk policies
have been reviewed with our Board of Directors and approved by our Risk
Executive Committee. Our Chief Risk Officer administers our risk policies and
procedures. The Risk Executive Committee establishes risk limits, approves risk
policies, and assigns responsibilities regarding the oversight and management of
risk and monitors risk levels. Members of this committee receive daily, weekly,
and monthly reports regarding compliance with policies, limits and procedures.
Our committee meets monthly and consists of the Chief Risk Officer, Chief Credit
Officer, V.P. Market Risk Oversight, and senior financial and operating
managers.
We actively participate in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around risk
management contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. The CCRO adopted disclosure
standards for risk management contracts to improve clarity, understanding and
consistency of information reported. Implementation of the disclosures is
voluntary. We support the work of the CCRO and have embraced the disclosure
standards. The following tables provide information on our risk management
activities.
Mark-to-Market Risk Management Contract Net Assets (Liabilities)
- ----------------------------------------------------------------
This table provides detail on changes in our mark-to-market (MTM) net asset or
liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets (Liabilities)
Year Ended December 31, 2003
Investments Investments
Utility Gas UK
Operations Operations Operations Consolidated
---------- ---------- ----------- ------------
(in millions)
Beginning Balance December 31, 2002 $ 360 $(155) $ 45 $ 250
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (107) 175 (9) 59
Fair Value of New Contracts When Entered
Into During the Period (b) - - 4 4
Net Option Premiums Paid/(Received) (c) - 23 (14) 9
Change in Fair Value Due to Valuation
Methodology Changes - 1 - 1
Effect of EITF 98-10 Rescission (d) (19) 1 (14) (32)
Changes in Fair Value of Risk Management
Contracts (e) 43 (40) (134) (131)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (f) 9 - - 9
UK Generation Hedges (g) - - (124) (124)
------ ------ ------ ------
Total MTM Risk Management Contract Net Assets
(Liabilities), excluding Cash Flow Hedges $ 286 $ 5 $(246) 45
====== ====== ======
Net Cash Flow Hedge Contracts (h) (134)
Net Risk Management Liabilities Held for Sale (i) 383
------
Ending Balance December 31, 2003 $ 294
======
(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 and entered into prior to
2003.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value at inception of long-term
contracts entered into with customers during 2003. 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 associated
with 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 entered into in 2003.
(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
Cumulative Effect."
(e) "Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(f) "Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
(g) "UK Generation Hedges" represent amounts previously classified as
hedges of forecasted U.K. power sales relating to the fourth
quarter of 2004 and beyond. Given the expected disposition of our
U.K. generation in 2004, the forecasted sales are no longer
probable of occurring. Therefore, these amounts have been
reclassified from hedge accounting to mark-to-market accounting.
(h) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail
within the following pages.
(i) See Note 10 for discussion on Assets Held for Sale.
Detail on MTM Risk Management Contract Net Assets (Liabilities)
As of December 31, 2003
Investments Investments
Utility Gas UK
Operations Operations Operations Consolidated
---------- ----------- ------------ ------------
(in millions)
Current Assets $ 323 $ 417 $ 560 $ 1,300
Non Current Assets 279 215 274 768
------ ------ -------- --------
Total Assets $ 602 $ 632 $ 834 $ 2,068
------ ------ -------- --------
Current Liabilities $(216) $(403) $ (646) $(1,265)
Non Current Liabilities (100) (224) (434) (758)
------ ------ -------- --------
Total Liabilities $(316) $(627) $(1,080) $(2,023)
------ ------ -------- --------
Total Net Assets (Liabilities),
excluding Cash Flow Hedges $ 286 $ 5 $ (246) $ 45
====== ====== ======== ========
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of December 31, 2003
Risk Management Cash Flow Assets Held
Contracts* Hedges for Sale Consolidated
--------------- --------- ----------- ------------
(in millions)
Current Assets $1,300 $26 $(560) $766
Non Current Assets 768 - (274) 494
-------- ------ ------- -------
Total Assets $2,068 $26 $(834) $1,260
-------- ------ ------- -------
Current Liabilities $(1,265) $(148) $782 $(631)
Non Current Liabilities (758) (12) 435 (335)
-------- ------ ------- -------
Total Liabilities $(2,023) $(160) $1,217 $(966)
-------- ------ ------- -------
Total Net Assets (Liabilities) $45 $(134) $383 $294
======== ====== ======= =======
* Excluding Cash Flow Hedges.
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
(Liabilities)
- ----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information.
. The source of fair value used in determining the carrying amount of our
total MTM asset or liability (external sources or modeled internally).
. The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of December 31, 2003
After
2004 2005 2006 2007 2008 2008 (c) Total (d)
------ ------ ------ ------ ------ --------- -----------
(in millions)
Utility Operations:
- ------------------
Prices Actively Quoted - Exchange Traded
Contracts $ 44 $ (4) $ (1) $ - $ - $ - $ 39
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 78 38 29 13 6 - 164
Prices Based on Models and Other
Valuation Methods (b) (15) 7 15 19 16 41 83
----- ------ ----- ---- ---- ---- ------
Total $107 $ 41 $ 43 $32 $22 $41 $ 286
===== ====== ===== ==== ==== ==== ======
Investments - Gas Operations:
- ----------------------------
Prices Actively Quoted - Exchange
Traded Contracts $ 49 $ 14 $ (1) $ - $ - $ - $ 62
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (27) - - - - - (27)
Prices Based on Models and Other
Valuation Methods (b) (8) (7) (6) (1) (3) (5) (30)
----- ------ ----- ---- ---- ---- ------
Total $ 14 $ 7 $ (7) $(1) $(3) $(5) $ 5
===== ====== ===== ==== ==== ==== ======
Investments - UK Operations:
- ---------------------------
Prices Actively Quoted - Exchange Traded
Contracts $ - $ - $ - $ - $ - $ - $-
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (60) (101) (46) - - - (207)
Prices Based on Models and Other
Valuation Methods (b) (26) (9) (2) (2) - - (39)
----- ------ ----- ---- ---- ---- ------
Total $(86) $(110) $(48) $(2) $ - $ - $(246)
===== ====== ===== ==== ==== ==== ======
Consolidated:
- ------------
Prices Actively Quoted - Exchange Traded
Contracts $ 93 $10 $ (2) $ - $ - $ - $ 101
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (9) (63) (17) 13 6 - (70)
Prices Based on Models and Other
Valuation Methods (b) (49) (9) 7 16 13 36 14
----- ------ ----- ---- ---- ---- ------
Total $ 35 $ (62) $(12) $29 $19 $36 $ 45
===== ====== ===== ==== ==== ==== ======
(a) Prices provided by other external sources - Reflects information obtained
from over-the-counter brokers, industry services, or multiple-party
on-line platforms.
(b) Modeled - In the absence of pricing information from external sources,
modeled information is derived using valuation models developed by the
reporting entity, reflecting when appropriate, option pricing theory,
discounted cash flow concepts, valuation adjustments, etc. and may
require projection of prices for underlying commodities beyond the period
that prices are available from third-party sources. In addition, where
external pricing information or market liquidity are limited, such
valuations are classified as modeled.
(c) For Utility Operations, there is mark-to-market value in excess of 10
percent of our total mark-to-market value in individual periods beyond
2008. $17 million of this mark-to-market value is in 2009 and $16 million
of this mark-to-market value is in 2010.
(d) Amounts exclude Cash Flow Hedges.
The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in the preceding table varies by market. The
following table reports an estimate of the maximum tenors (contract maturities)
of the liquid portion of each energy market.
Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of December 31, 2003
Domestic Transaction Class Market/Region Tenor
-------- ----------------- ------------- -----
(in months)
Natural Gas Futures NYMEX Henry Hub 72
Physical Forwards Gulf Coast, Texas 12
Swaps Gas East - Northeast, Mid-continent
Gulf Coast, Texas 15
Swaps Gas West - Rocky Mountains,
West Coast 15
Exchange Option Volitility NYMEX/Henry Hub 12
Power Futures Power East - PJM 24
Physical Forwards Power East - Cinergy 60
Physical Forwards Power East - PJM 48
Physical Forwards Power East - NYPP 24
Physical Forwards Power East - NEPOOL 12
Physical Forwards Power East - ERCOT 24
Physical Forwards Power East - TVA 48
Physical Forwards Power East - Com Ed 24
Physical Forwards Power East - Entergy 48
Physical Forwards Power West - PV, NP15, SP15,
MidC, Mead 60
Peak Power Volatility
(Options) Cinergy 12
Peak Power Volatility
(Options) PJM 12
Crude Oil Swaps West Texas Intermediate 36
Emissions Credits SO2 24
Coal Physical Forwards PRB,NYMEX,CSX 24
International
-------------
Power Forwards and Options United Kingdom 24
Coal Forward Purchases and Sales United Kingdom 15
Swaps Europe 36
Freight Swaps Europe 24
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) on
the Balance Sheet
- -----------------------------------------------------------------------------
We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments such as cash flow hedges to mitigate the impact of
these fluctuations on the future cash flows from assets. We do not hedge all
commodity price risk.
We employ fair value hedges and cash flow hedges 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 forward contracts
as cash flow hedges to lock-in prices on certain transactions which have been
denominated in foreign currencies where deemed necessary. International
subsidiaries use currency swaps to hedge exchange rate fluctuations of debt
denominated in foreign currencies. We do not hedge all foreign currency
exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place (However, given that under SFAS 133 only cash flow
hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the table
does not provide an all-encompassing picture of our hedging activity). The table
further indicates what portions of these hedges are expected to be reclassified
into net income in the next 12 months. The table also includes a roll-forward of
the AOCI balance sheet account, providing insight into the drivers of the
changes (new hedges placed during the period, changes in value of existing
hedges and roll off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Cash Flow Hedges included in Accumulated Other Comprehensive Income (Loss)
On the Balance Sheet as of December 31, 2003
Portion Expected to
Accumulated Other be Reclassified to
Comprehensive Income Earnings During the
(Loss) After Tax (a) Next 12 Months (b)
-------------------- -------------------
(in millions)
Power and Gas $(65) $(58)
Foreign Currency (20) (20)
Interest Rate (9) (8)
----- -----
Total $(94) $(86)
===== =====
Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2003
Power Foreign
and Gas Currency Interest Rate Consolidated
------- -------- ------------- ------------
(in millions)
Beginning Balance, December 31, 2002 $ (3) $ (1) $(12) $(16)
Changes in Fair Value (c) (64) (19) 4 (79)
Reclassifications from AOCI to Net Income (d) 2 - (1) 1
----- ----- ----- -----
Ending Balance,
December 31, 2003 $(65) $(20) $ (9) $(94)
===== ===== ===== =====
(a) "Accumulated Other Comprehensive Income (Loss) After Tax" -
Gains/losses are net of related income taxes that have not yet been
included in the determination of net income; reported as a separate
component of shareholders' equity on the balance sheet.
(b) "Portion Expected to be Reclassified to Earnings During the Next 12
Months" - Amount of gains or losses (realized or unrealized) from
derivatives used as hedging instruments that have been deferred and
are expected to be reclassified into net income during the next 12
months at the time the hedged transaction affects net income.
(c) "Changes in Fair Value" - Changes in the fair value of derivatives
designated as cash flow hedges not yet reclassified into net income,
pending the hedged items affecting net income. Amounts are reported
net of related income taxes.
(d) "Reclassifications from AOCI to Net Income" - Gains or losses from
derivatives used as hedging instruments in cash flow hedges that were
reclassified into net income during the reporting period. Amounts are
reported net of related income taxes above.
Credit Risk
- -----------
We limit credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continue to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met our internal credit rating criteria will we extend unsecured credit. We
use 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. Our independent analysis, in conjunction with the rating
agencies' information, is used to determine appropriate risk parameters. We also
require cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.
We have risk management contracts with numerous counterparties. Since open risk
management contracts are valued based on changes in market prices of the related
commodities, our exposures change daily. We believe that credit exposure with
any one counterparty is not material to our financial condition at December 31,
2003. At December 31, 2003, our credit exposure net of credit collateral to sub
investment grade counterparties was approximately 16%, expressed in terms of net
MTM assets and net receivables. The increase in non-investment grade credit
quality was largely due to an increase in coal and freight exposures related to
our U.K. investments. As of December 31, 2003, the following table approximates
our counterparty credit quality and exposure based on netting across commodities
and instruments:
Number of Net Exposure of
Counterparty Exposure Before Credit Net Counterparties Counterparties
Credit Quality: Credit Collateral Collateral Exposure ** 10% **10%
- -------------- ----------------- ---------- -------- -------------- ---------------
(in millions)
Investment Grade $ 931 $ 29 $ 902 1 $135
Split Rating 47 - 47 1 40
Non-Investment Grade 276 136 140 2 71
No External Ratings:
Internal Investment
Grade 480 5 475 3 207
Internal Non-Investment
Grade 185 48 137 2 51
------- ----- ------- --- -----
Total $1,919 $218 $1,701 9 $504
======= ===== ======= === =====
** Is greater than.
Generation Plant Hedging Information
- ------------------------------------
This table provides information on operating measures regarding the proportion
of output of our generation facilities (based on economic availability
projections) economically hedged. This information is forward-looking and
provided on a prospective basis through December 31, 2006. Please note that this
table is a point-in-time estimate, subject to changes in market conditions and
our decisions on how to manage operations and risk. "Estimated Plant Output
Hedged," represents the portion of megawatt hours of future
generation/production for which we have sales commitments or estimated
requirement obligations to customers.
Generation Plant Hedging Information
Estimated Next Three Years
As of December 31, 2003
2004 2005 2006
---- ---- ----
Estimated Plant Output Hedged 90% 92% 92%
VaR Associated with Risk Management Contracts
- ---------------------------------------------
We use a risk measurement model, which calculates Value at Risk (VaR) to measure
our commodity price risk in the risk management portfolio. The VaR is based on
the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes a 95% confidence level and a one-day
holding period. Based on this VaR analysis, at December 31, 2003, a near term
typical change in commodity prices is not expected to have a material effect on
our results of operations, cash flows or financial condition.
The following table shows the end, high, average, and low market risk as
measured by VaR year-to-date:
VaR Model
December 31, 2003 December 31, 2002
-------------------------- ------------------------
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$11 $19 $ 7 $4 $5 $24 $12 $4
The high VaR for 2003 occurred in late February 2003 during a period when
natural gas and power prices experienced high levels and extreme volatility.
Within a few days, the VaR returned to levels more representative of the average
VaR for the year.
Our VaR model results are adjusted using standard statistical treatments to
calculate the CCRO VaR reporting metrics listed below.
CCRO VaR Metrics
Average for
Year-to-Date High for Low for
December 31, 2003 2003 Year-to-Date 2003 Year-to-Date 2003
------------------ ------------ ------------------ -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period $41 $27 $71 $16
99% Confidence Level, One-Day
Holding Period $17 $11 $30 $ 7
We 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 daily prices. The risk of potential
loss in fair value attributable to our exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $1.013 billion at
December 31, 2003 and $527 million at December 31, 2002. We would not expect to
liquidate our entire debt portfolio in a one-year holding period, therefore a
near term change in interest rates should not materially affect our results of
operations or consolidated financial position.
We are 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 West
Virginia. To the extent the fuel supply of the generating units in these states
is not under fixed price long-term contracts we are subject to market price
risk. We continue to be protected against market price changes by active fuel
clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of
Texas. Fuel clauses are active again in Michigan and Texas, effective January 1,
2004 and March 1, 2004, respectively.
We employ risk management contracts including 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. We engage in
risk management of electricity, gas and to a lesser degree other commodities,
principally coal and freight. As a result, we are subject to price risk. The
amount of risk taken is controlled by risk management operations and our Chief
Risk Officer and his staff. When risk management activities exceed 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.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2003, 2002 and 2001
(in millions, except per-share amounts)
2003 2002 2001
---- ---- ----
REVENUES
- --------------------------------------------------------------
Utility Operations $10,871 $10,446 $10,546
Gas Operations 3,097 2,071 1,797
Other 577 791 410
-------- -------- --------
TOTAL 14,545 13,308 12,753
-------- -------- --------
EXPENSES
- --------------------------------------------------------------
Fuel for Electric Generation 3,053 2,577 3,225
Purchased Electricity for Resale 707 532 296
Purchased Gas for Resale 2,850 1,946 1,443
Maintenance and Other Operation 3,673 4,065 3,666
Asset Impairments and Other Related Charges 650 318 -
Depreciation and Amortization 1,299 1,348 1,233
Taxes Other Than Income Taxes 681 718 667
-------- -------- --------
TOTAL 12,913 11,504 10,530
-------- -------- --------
OPERATING INCOME 1,632 1,804 2,223
-------- -------- --------
Other Income 387 461 371
-------- -------- --------
INTEREST AND OTHER CHARGES
- --------------------------------------------------------------
Investment Value Losses 70 321 -
Other Expenses 227 323 225
Interest 814 775 833
Preferred Stock Dividend Requirements of Subsidiaries 9 11 10
Minority Interest in Finance Subsidiary 19 35 13
-------- -------- --------
TOTAL 1,139 1,465 1,081
-------- -------- --------
INCOME BEFORE INCOME TAXES 880 800 1,513
Income Taxes 358 315 553
-------- -------- --------
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND
CUMULATIVE EFFECT 522 485 960
DISCONTINUED OPERATIONS (Net of Tax) (605) (654) 41
EXTRAORDINARY LOSS (Net of Tax) - - (48)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (Net of Tax)
- --------------------------------------------------------------
Goodwill and Other Intangible Assets - (350) 18
Accounting for Risk Management Contracts (49) - -
Asset Retirement Obligations 242 - -
-------- -------- --------
NET INCOME (LOSS) $ 110 $ (519) $ 971
-------- -------- --------
AVERAGE NUMBER OF SHARES OUTSTANDING 385 332 322
-------- -------- --------
EARNINGS (LOSS) PER SHARE
- --------------------------------------------------------------
Income Before Discontinued Operations, Extraordinary Items and
Cumulative Effect of Accounting Changes $ 1.35 $ 1.46 $ 2.98
Discontinued Operations (1.57) (1.97) 0.13
Extraordinary Loss - - (0.16)
Cumulative Effect of Accounting Changes 0.51 (1.06) 0.06
-------- -------- --------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE) $ 0.29 $ (1.57) $ 3.01
-------- -------- --------
CASH DIVIDENDS PAID PER SHARE $ 1.65 $ 2.40 $ 2.40
-------- -------- --------
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2003 and 2002
2003 2002
---- ----
(in millions)
CURRENT ASSETS
- ---------------------------------------------------------------------------
Cash and Cash Equivalents $ 1,182 $ 1,199
Accounts Receivable:
Customers 1,155 1,553
Accrued Unbilled Revenues 596 551
Miscellaneous 83 93
Allowance for Uncollectible Accounts (124) (108)
-------- --------
Total Receivables 1,710 2,089
-------- --------
Fuel, Materials and Supplies 991 938
Risk Management Assets 766 850
Margin Deposits 119 110
Other 129 132
-------- --------
TOTAL 4,897 5,318
-------- --------
PROPERTY, PLANT AND EQUIPMENT
- ---------------------------------------------------------------------------
Electric:
Production 15,112 13,678
Transmission 6,130 5,866
Distribution 9,902 9,573
Other (including gas, coal mining and nuclear fuel) 3,584 3,656
Construction Work in Progress 1,305 1,354
-------- --------
TOTAL 36,033 34,127
Less: Accumulated Depreciation and Amortization 14,004 13,539
-------- --------
TOTAL-NET 22,029 20,588
-------- --------
OTHER NON-CURRENT ASSETS
- ---------------------------------------------------------------------------
Regulatory Assets 3,548 2,688
Securitized Transition Assets 689 735
Spent Nuclear Fuel and Decommissioning Trusts 982 871
Investments in Power and Distribution Projects 212 283
Goodwill 78 241
Long-term Risk Management Assets 494 758
Other 733 792
-------- --------
TOTAL 6,736 6,368
-------- --------
Assets Held for Sale 3,082 3,601
Assets of Discontinued Operations - 15
TOTAL ASSETS $36,744 $35,890
======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
December 31, 2003 and 2002
2003 2002
---- ----
(in millions)
CURRENT LIABILITIES
- ---------------------------------------------------------------------------
Accounts Payable $ 1,337 $ 1,892
Short-term Debt 326 2,739
Long-term Debt Due Within One Year* 1,779 1,327
Risk Management Liabilities 631 961
Accrued Taxes 620 556
Accrued Interest 207 181
Customer Deposits 379 186
Other 703 814
-------- --------
TOTAL 5,982 8,656
-------- --------
NON-CURRENT LIABILITIES
- ---------------------------------------------------------------------------
Long-term Debt* 12,322 8,863
Long-term Risk Management Liabilities 335 435
Deferred Income Taxes 3,957 3,916
Regulatory Liabilities and Deferred Investment Tax Credits 2,259 939
Asset Retirement Obligations and Nuclear Decommissioning Trusts 651 638
Employee Benefits and Pension Obligations 667 987
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 176 185
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption 76 -
Deferred Credits and Other 508 1,691
-------- --------
TOTAL 20,951 17,654
-------- --------
Liabilities Held for Sale 1,876 1,279
Liabilities of Discontinued Operations - 12
TOTAL LIABILITIES 28,809 27,601
-------- --------
Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption 61 -
Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries - 321
Minority Interest in Finance Subsidiary - 759
Cumulative Preferred Stocks of Subsidiaries - 145
Commitments and Contingencies
COMMON SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------
Common Stock-Par Value $6.50:
2003 2002
---- ----
Shares Authorized. . . . . . . . . . .600,000,000 600,000,000
Shares Issued. . . . . . . . . . . . .404,016,413 347,835,212
(8,999,992 shares were held in treasury at December 31, 2003 and 2002) 2,626 2,261
Paid-in Capital 4,184 3,413
Retained Earnings 1,490 1,999
Accumulated Other Comprehensive Income (Loss) (426) (609)
-------- --------
TOTAL 7,874 7,064
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $36,744 $35,890
======== ========
* See Accompanying Schedules
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002 and 2001
2003 2002 2001
---- ---- ----
(in millions)
OPERATING ACTIVITIES
- ---------------------------------------------------------------------------
Net Income (Loss) $ 110 $ (519) $ 971
Plus: Discontinued Operations 605 654 (41)
-------- -------- --------
Income from Continuing Operations 715 135 930
Adjustments for Noncash Items:
Depreciation and Amortization 1,299 1,375 1,267
Deferred Income Taxes 163 63 151
Deferred Investment Tax Credits (33) (31) (29)
Pension and Postemployment Benefits Reserves (74) 39 (234)
Cumulative Effect of Accounting Changes (193) 350 (18)
Asset and Investment Value Impairments and Other Related Charges 720 639 -
Extraordinary Loss - - 48
Amortization of Deferred Property Taxes (2) (16) 43
Amortization of Cook Plant Restart Costs 40 40 40
Mark to Market of Risk Management Contracts (122) 275 (294)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable, net 363 (238) 1,769
Fuel, Materials and Supplies (71) (102) (82)
Accounts Payable (632) (21) (469)
Taxes Accrued 87 (222) (150)
Over/Under Fuel Recovery 138 13 340
Change in Other Assets (162) (78) (171)
Change in Other Liabilities 72 (154) (323)
-------- -------- --------
Net Cash Flows From Operating Activities 2,308 2,067 2,818
-------- -------- --------
INVESTING ACTIVITIES
- ---------------------------------------------------------------------------
Construction Expenditures (1,358) (1,685) (1,646)
Business Acquisitions - - (1,269)
Investment in Discontinued Operations, net (615) - (983)
Proceeds from Sale of Assets 82 1,263 648
Other 3 44 (42)
-------- -------- --------
Net Cash Flows Used For Investing Activities (1,888) (378) (3,292)
-------- -------- --------
FINANCING ACTIVITIES
- ---------------------------------------------------------------------------
Issuance of Common Stock 1,142 656 11
Issuance of Long-term Debt 4,761 2,893 2,787
Issuance of Minority Interest - - 744
Issuance of Equity Unit Senior Notes - 334 -
Change in Short-term Debt, net (2,781) (1,248) (778)
Retirement of Long-term Debt (2,707) (2,513) (1,549)
Retirement of Preferred Stock (9) (10) (5)
Retirement of Minority Interest (225) - -
Dividends Paid on Common Stock (618) (793) (773)
-------- -------- --------
Net Cash Flows From (Used For) Financing Activities (437) (681) 437
-------- -------- --------
Effect of Exchange Rate Change on Cash - (3) (1)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (17) 1,005 (38)
Cash and Cash Equivalents at Beginning of Period 1,199 194 232
-------- -------- --------
Cash and Cash Equivalents at End of Period $ 1,182 $ 1,199 $ 194
======== ======== ========
Net Increase (Decrease) in Cash and Cash Equivalents from Discontinued Operations $ (10) $ (116) $ 29
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 23 139 110
-------- -------- --------
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 13 $ 23 $ 139
======== ======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
COMPREHENSIVE INCOME (LOSS)
(in millions)
Accumulated
Other
Common Stock Paid-in Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
------ ------ ------- -------- ------------- -----
DECEMBER 31, 2000 331 $2,152 $2,915 $3,090 $(103) $8,054
Issuance of Common Stock 1 9 10
Common Stock Dividends (773) (773)
Other (18) 8 (10)
-------
TOTAL 7,281
-------
COMPREHENSIVE INCOME (LOSS)
- ------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments (14) (14)
Unrealized Losses on Cash Flow Hedges (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
Issuance of Common Stock 17 108 568 676
Common Stock Dividends (793) (793)
Common Stock Expense (30) (30)
Other (31) 15 (16)
-------
TOTAL 8,066
-------
COMPREHENSIVE INCOME (LOSS)
- ------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 117 117
Unrealized Losses on Cash Flow Hedges (13) (13)
Unrealized Losses on Securities Available for Sale (2) (2)
Minimum Pension Liability (585) (585)
NET LOSS (519) (519)
-------
TOTAL COMPREHENSIVE INCOME (LOSS) (1,002)
----- ------- ------- ------- ------ -------
DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064
Issuance of Common Stock 56 365 812 1,177
Common Stock Dividends (618) (618)
Common Stock Expense (35) (35)
Other (6) (1) (7)
-------
TOTAL 7,581
-------
COMPREHENSIVE INCOME (LOSS)
- ------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 106 106
Unrealized Losses on Cash Flow Hedges (78) (78)
Unrealized Gains on Securities Available for Sale 1 1
Minimum Pension Liability 154 154
NET INCOME 110 110
-------
TOTAL COMPREHENSIVE INCOME 293
----- ------- ------- ------- ------ -------
DECEMBER 31, 2003 404 $2,626 $4,184 $1,490 $(426) $7,874
===== ======= ======= ======= ====== =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 2003 and 2002
December 31, 2003
--------------------------------------------------------------------------------
Call Shares Shares Amount
Price Per Share(a) Authorized(b) Outstanding(d) (in millions)
------------------ ------------- -------------- -------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 607,940 $ 61
----
Subject to Mandatory Redemption:
5.90% - 5.92% (c) $100 1,950,000 278,100 28
6.25% - 6.875% (c) $100 1,650,000 482,450 48
----
Total Subject to Mandatory
Redemption (c) 76
----
Total Preferred Stock $137 (e)
====
December 31, 2002
--------------------------------------------------------------------------------
Call Shares Shares Amount
Price Per Share(a) Authorized(b) Outstanding(d) (in 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) $100 1,950,000 333,100 33
6.02% - 6.875% (c) $100 1,650,000 513,450 51
----
Total Subject to Mandatory
Redemption (c) 84
----
Total Preferred Stock $145
====
(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, 2003, the subsidiaries had 13,780,352 shares of
$100 par value preferred stock, 22,200,000 shares of $25 par value
preferred stock and 7,768,561 shares of no par value preferred stock
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) The number of shares of preferred stock redeemed is 86,210 shares in
2003, 106,458 shares in 2002 and 50,000 shares in 2001.
(e) Due to the implementation of SFAS 150 in July 2003, Cumulative Preferred
Stocks of Subsidiaries is no longer presented as one line item on the
balance sheet. SFAS 150 has required us to present Cumulative Preferred
Stocks of Subsidiaries Subject to Mandatory Redemption as a liability.
Cumulative Preferred Stocks of Subsidiaries Not Subject to Mandatory
Redemption will continue to be reported on the balance sheet in the
"mezzanine" section.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
December 31, 2003 and 2002
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
- -------- ----------------- ------------------------------ ----------------
December 31, 2003 2003 2002 2003 2002
----------------- ---- ---- ---- ----
(in millions)
FIRST MORTGAGE BONDS (a)
2003-2004 7.40% 6.125%-7.85% 6.00%-7.85% $ 231 $ 648
2005-2008 6.90% 6.20%-8.00% 6.20%-8.00% 463 463
2022-2025 7.28% 6.875%-8.00% 6.875%-8.70% 246 773
INSTALLMENT PURCHASE CONTRACTS (b)(f)
2003-2009 3.74% 2.15%-6.90% 3.75%-7.70% 395 396
2011-2030 4.92% 1.10%-8.20% 1.35%-8.20% 1,631 1,284
NOTES PAYABLE (c)(f)
2003-2017 5.20% 1.537%-15.45% 6.225%-9.60% 1,518 214
SENIOR UNSECURED NOTES
2003-2005 5.10% 2.43%-7.45% 2.12%-7.45% 1,359 1,834
2006-2015 5.49% 3.60%-6.91% 4.31%-6.91% 4,873 2,295
2032-2038 6.41% 5.625%-7.375% 6.00%-7.375% 1,765 690
JUNIOR DEBENTURES
2025-2038 - - 7.60%-8.72% - 205
SECURITIZATION BONDS
2005-2016 5.53% 3.54%-6.25% 3.54%-6.25% 746 797
NOTES PAYABLE TO TRUST (d)
2037-2043 7.06% 5.25-8.00% - 331 -
EQUITY UNIT SENIOR NOTES (e)
2007 5.75% 5.75% 5.75% 345 345
OTHER LONG-TERM DEBT (g) 247 247
Equity Unit Contract Adjustment Payments 19 31
Unamortized Discount (net) (68) (32)
-------- --------
Total Long-term Debt Outstanding 14,101 10,190
Less Portion Due Within One Year 1,779 1,327
-------- --------
Long-term Portion $12,322 $ 8,863
======== ========
(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) Notes Payable to Trust is a result of a deconsolidation of TCC, PSO and
SWEPCo's trusts effective July 1, 2003 due to the implementation of FIN
46. See Notes 2 and 17 for further information.
(e) In May 2005, the interest rate on these Equity Unit Senior Notes can be
reset through a remarketing.
(f) Installment Purchase Contracts and Notes Payable include $257 million and
$185 million, respectively, due to the implementation of FIN 46 (see Note
2). Notes Payable includes $496 million of a merchant power generation
facility which was consolidated as of December 31, 2003 (see Notes 10 and
16).
(g) Other long-term debt consists of a liability along with accrued interest
for disposal of spent nuclear fuel (see Note 7) and a financing obligation
under a sale and leaseback agreement.
LONG-TERM DEBT OUTSTANDING AT DECEMBER 31, 2003 IS PAYABLE AS FOLLOWS:
- ----------------------------------------------------------------------
2004 2005 2006 2007 2008 Later Years TOTAL
---- ---- ---- ---- ---- ----------- -----
(in millions)
Principal Amount $1,779 $1,273 $2,187 $1,124 $587 $7,200 $14,150
Equity Unit Contract Adjustment Payments 19
Unamortized Discount (68)
--------
$14,101
========
AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES
INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------------------
1. Organization and Summary of Significant Accounting Policies
2. New Accounting Pronouncements, Extraordinary Items and Cumulative
Effect of Accounting Changes
3. Goodwill and Other Intangible Assets
4. Rate Matters
5. Effects of Regulation
6. Customer Choice and Industry Restructuring
7. Commitments and Contingencies
8. Guarantees
9. Sustained Earnings Improvement Initiative
10. Acquisitions, Dispositions, Discontinued Operations, Impairments,
Assets Held for Sale and Assets Held and Used
11. Benefit Plans
12. Stock-Based Compensation
13. Business Segments
14. Derivatives, Hedging and Financial Instruments
15. Income Taxes
16. Leases
17. Financing Activities
18. Unaudited Quarterly Financial Information
19. Subsequent Events (Unaudited)
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
--------------------------------------------------------------
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------------------
ORGANIZATION
- ------------
Our principal business conducted by our 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 maintain accounts in accordance with FERC and other regulatory
guidelines. These companies are subject to further regulation with regard to
rates and other matters by state regulatory commissions.
We also engage in wholesale electricity, natural gas and other commodity
marketing and risk management activities in the United States and Europe. In
addition, our domestic operations include non-regulated independent power and
cogeneration facilities, coal mining and intra-state natural gas operations in
Louisiana and Texas.
International operations include the generation and supply of power in the
United Kingdom, and to a lesser extent in Mexico, Australia and China. These
operations are either wholly-owned or partially-owned by our various
subsidiaries.
We also conduct domestic barging operations, provide various energy related
services and furnish communications-related services domestically.
During 2003 we announced plans to significantly restructure and dispose of many
of our non-regulated operations. See Note 10 for a discussion of the impacts of
these plans on our organization.
Certain previously reported amounts have been reclassified to conform to current
classifications with no effect on net income or shareholders' equity.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ------------------------------------------
Rate Regulation
- ---------------
We are 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 and Mexico are regulated by the
authorities of those countries and are generally subject to price controls.
Principles of Consolidation
- ---------------------------
Our consolidated financial statements include AEP and its wholly-owned and
majority-owned subsidiaries consolidated with their wholly-owned subsidiaries or
substantially controlled variable interest entities. Intercompany items are
eliminated in consolidation. Equity investments not substantially controlled
that are 50% or less owned are accounted for using the equity method of
accounting; equity earnings are included in Other Income. We also have
generating units that are jointly owned with unaffiliated companies. The
proportionate share of the operating costs associated with such facilities is
included in our Consolidated Statements of Operations and the investments are
reflected in our Consolidated Balance Sheets.
Accounting for the Effects of Cost-Based Regulation
- ---------------------------------------------------
As the owner of cost-based rate-regulated electric public utility companies, our
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. 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. We discontinued the application of SFAS 71
for the generation portion of our business 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, in Arkansas by SWEPCo in September
1999 and in the FERC jurisdiction for TNC in December 2003. During 2003, APCo
reapplied SFAS 71 for West Virginia and SWEPCo reapplied SFAS 71 for Arkansas.
Use of Estimates
- ----------------
The preparation of these financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the amounts reported in
the financial statements and accompanying notes. These estimates include but are
not limited to inventory valuation, allowance for doubtful accounts, goodwill
and intangible asset impairment, unbilled electricity revenue, values of
long-term energy contracts, the effects of regulation, long-lived asset
recovery, the effects of contingencies and certain assumptions made in
accounting for pension benefits. Actual results could differ from those
estimates.
Property, Plant and Equipment
- -----------------------------
Domestic electric utility property, plant and equipment are stated at original
purchase cost. Property, plant and equipment of the non-regulated operations and
other investments are stated at their fair market value at acquisition (or as
adjusted for any applicable impairments) 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. For
non-regulated operations, retirements from the plant accounts and associated
salvage are deducted from accumulated depreciation and removal costs are charged
to expense. The costs of labor, materials and overhead incurred to operate and
maintain plant are included in operating expenses. Assets are tested for
impairment as required under SFAS 144 (see Note 10).
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- --------------------------------------------------------------------------------
AFUDC represents the estimated cost of borrowed and equity funds used to finance
construction projects that is capitalized and recovered through depreciation
over the service life of domestic regulated electric utility plant. For
non-regulated operations, interest is capitalized during construction in
accordance with SFAS 34, "Capitalization of Interest Costs." Capitalized
interest is also recorded for domestic generating assets in Ohio, Texas and
Virginia, effective with the discontinuance of SFAS 71 regulatory accounting.
The amounts of AFUDC and interest capitalized were not material in 2003, 2002
and 2001.
Depreciation, Depletion and Amortization
- ----------------------------------------
We provide for depreciation of property, plant and equipment on a straight-line
basis over the estimated useful lives of property, excluding coal-mining
properties, generally using composite rates by functional class as follows:
Functional Class of Property Annual Composite Depreciation Rates Ranges
- ---------------------------- ----------------------------------------------------------
2003 2002 2001
-------------- ------------- -------------
Production:
Steam-Nuclear 2.5% to 3.4% 2.5% to 3.4% 2.5% to 3.4%
Steam-Fossil-Fired 2.3% to 4.6% 2.6% to 4.5% 2.5% to 4.5%
Hydroelectric-Conventional
and Pumped Storage 1.9% to 3.4% 1.9% to 3.4% 1.9% to 3.4%
Transmission 1.7% to 2.8% 1.7% to 3.0% 1.7% to 3.1%
Distribution 3.3% to 4.2% 3.3% to 4.2% 2.7% to 4.2%
Other 1.8% to 16.7% 1.8% to 9.9% 1.8% to 15.0%
We provide for depreciation, depletion and amortization of coal-mining assets
over each asset's estimated useful life or the estimated life of each mine,
whichever is shorter, using the straight-line method for mining structures and
equipment. We use either the straight-line method or the units-of-production
method to amortize mine development costs and deplete coal rights based on
estimated recoverable tonnages. We include these costs in the cost of coal
charged to fuel expense. Average amortization rates for coal rights and mine
development costs were $0.25 per ton in 2003, $0.32 per ton in 2002 and $2.06
per ton in 2001. In 2002, certain coal-mining assets were impaired by $60
million leading to the decline in amortization rates in 2003. In 2001, an AEP
subsidiary sold coal mines in Ohio and West Virginia leading to the decline in
amortization rates in 2002.
Valuation of Non-Derivative Financial Instruments
- -------------------------------------------------
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.
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. During 2003 a fair value hedging strategy was implemented for certain
non-trading gas and coal inventory. Changes in the fair value of hedged
inventory are recorded to the extent offsetting hedges are designated against
that inventory.
Accounts Receivable
- -------------------
Customer accounts receivable primarily includes receivables from wholesale and
retail energy customers, receivables from energy contract counterparties related
to our risk management activities and customer receivables primarily related to
other revenue-generating activities.
We recognize revenue from electric power and gas sales when we deliver power or
gas to our customers. To the extent that deliveries have occurred but a bill has
not been issued, we accrue and recognize, as Accrued Unbilled Revenues, an
estimate of the revenues for energy delivered since the latest billings.
AEP Credit, Inc. factors accounts receivable for certain registrant
subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and
a portion of APCo. Since APCo does not have regulatory authority to sell
accounts receivable in all of its regulatory jurisdictions, only a portion of
APCo's accounts receivable are sold to AEP Credit. AEP Credit has a sale of
receivables agreement with banks and commercial paper conduits. Under the sale
of receivables agreement, 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 the company's balance sheet. See
Note 17 "Financing Activities" for further details.
Foreign Currency Translation
- ----------------------------
The financial statements of subsidiaries outside the U.S. which are included in
our 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." Although the effects of foreign currency
fluctuations are mitigated by the fact that expenses of foreign subsidiaries are
generally incurred in the same currencies in which sales are generated, the
reported results of operations of our foreign subsidiaries are affected by
changes in foreign currency exchange rates and, as compared to prior periods,
will be higher or lower depending upon a weakening or strengthening of the U.S.
dollar. Revenues and expenses are translated at monthly average foreign currency
exchange rates throughout the year. Assets and liabilities are translated into
U.S. dollars at year-end foreign currency exchange rates. Accordingly, our
consolidated common shareholders' equity will fluctuate depending on the
relative strengthening or weakening of the U.S. dollar versus relevant foreign
currencies. Currency translation gain and loss adjustments are recorded in
shareholders' equity as Accumulated Other Comprehensive Income (Loss). The
impact of the changes in exchange rates on cash, resulting from the translation
of items at different exchange rates, is shown on our Consolidated Statements of
Cash Flows in Effect of Exchange Rate Change on Cash. Actual currency
transaction gains and losses are recorded in income when they occur.
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 (the excess of fuel revenues billed to ratepayers over fuel
costs incurred) are deferred as regulatory liabilities and under-recoveries (the
excess of fuel costs incurred over fuel revenues billed to ratepayers) are
deferred as regulatory assets. These deferrals are amortized when refunded or
billed to customers in later months with the regulator's review and approval.
The amounts of an over-recovery or under-recovery can also be affected by
actions of regulators. When these actions become probable we adjust our
deferrals to recognize these probable outcomes. The amount of under-recovered
fuel costs deferred under fuel clauses as a regulatory asset was $51 million at
December 31, 2003 and $148 million at December 31, 2002. The amount of
over-recovered fuel costs deferred under fuel clauses as a regulatory liability
was $132 million at December 31, 2003 and $90 million at December 31, 2002. See
Note 5 "Effects of Regulation" for further information.
In general, changes in fuel costs in Kentucky for KPCo, the SPP area of Texas,
Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo are
timely reflected in rates through the fuel cost adjustment clauses in place in
those states. 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 have also
impacted earnings. The Michigan fuel clause suspension ended December 31, 2003,
and the Indiana freeze is scheduled to end on March 1, 2004. Changes in fuel
costs also impact earnings for certain of our Independent Power Producer
generating units that do not have long-term contracts for their fuel supply. See
Note 4, "Rate Matters" and Note 6, "Customer Choice and Industry Restructuring"
for further information about fuel recovery.
Revenue Recognition
- -------------------
Regulatory Accounting
- ---------------------
Our consolidated financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate-regulated. 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 or regulatory assets are also recorded for unrealized
gains or losses that occur due to changes in the fair value of physical and
financial contracts that are derivatives and that are subject to the regulated
ratemaking process.
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 it is determined 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 statement 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, with the
exception of certain physical forward gas purchase and sale contracts that are
derivatives and that are accounted for using mark-to-market accounting (Resale
Gas Contracts).
Energy Marketing and Risk Management Activities
- -----------------------------------------------
We engage in wholesale electricity, natural gas and coal marketing and risk
management activities. Effective in October 2002, these activities were focused
on wholesale markets where we own assets. Our activities include 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. Prior to October
2002, we recorded wholesale marketing and risk management activities using the
mark-to-market method of accounting.
In October 2002, EITF 02-3 precluded mark-to-market accounting for risk
management contracts that were not derivatives pursuant to SFAS 133. We
implemented this standard for all non-derivative wholesale and risk management
transactions occurring on or after October 25, 2002. For non-derivative risk
management transactions entered into prior to October 25, 2002, we implemented
this standard on January 1, 2003 and reported the effects of implementation as a
cumulative effect of an accounting change.
After January 1, 2003, we use mark-to-market accounting for wholesale marketing
and risk management transactions that are derivatives unless the derivative is
designated for hedge accounting or the normal purchase and sale exemption.
Revenues and expenses are recognized from wholesale marketing and risk
management transactions that are not derivatives when the commodity is
delivered.
See discussion of EITF 02-3 and Rescission of EITF 98-10 in Note 2.
Accounting for Derivative Instruments
- -------------------------------------
We use the mark-to-market method of accounting for derivative contracts.
Unrealized gains and losses prior to settlement, resulting from revaluation of
these contracts to fair value during the period, are recognized currently. When
the derivative contracts are settled and gains and losses are realized, the
previously recorded unrealized gains and losses from mark-to-market valuations
are reversed.
Certain derivative instruments are designated as a hedge of a forecasted
transaction or future cash flow (cash flow hedge) or as a hedge of a recognized
asset, liability or firm commitment (fair value hedge). The gains or losses on
derivatives designated as fair value hedges are recognized in Revenues in the
Consolidated Statement of Operations in the period of change together with the
offsetting losses or gains on the hedged item attributable to the risks being
hedged. For derivatives designated as cash flow hedges, the effective portion of
the derivative's gain or loss is initially reported as a component of
Accumulated Other Comprehensive Income and subsequently reclassified into
Revenues in the Consolidated Statement of Operations when the forecasted
transaction affects earnings. The ineffective portion of the gain or loss is
recognized in Revenues in the Consolidated Statement of Operations immediately
(see Note 14).
The fair values of derivative instruments accounted for using mark-to-market
accounting or hedge accounting are based on exchange prices and broker quotes.
If a quoted market price is not available, the estimate of fair value is based
on the best information available including 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. 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 risk management 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 a contract settles. Therefore,
there could be significant adverse or favorable effects on future results of
operations and cash flows if market prices are not consistent with our approach
at estimating current market consensus for forward prices in the current period.
This is particularly true for long-term contracts.
We recognize all derivative instruments at fair value in our Consolidated
Balance Sheets as either "Risk Management Assets" or "Risk Management
Liabilities." We do not consider contracts that have been elected normal
purchase or normal sale under SFAS 133 to be derivatives. Unrealized and
realized gains and losses on all derivative instruments are ultimately included
in Revenues in the Consolidated Statement of Operations on a net basis, with the
exception of physically settled Resale Gas Contracts for the purchase of natural
gas. The unrealized and realized gains and losses on these Resale Gas Contracts
are presented as Purchased Gas for Resale in the Consolidated Statement of
Operations.
Construction Projects for Outside Parties
- -----------------------------------------
Our 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,
we enter into contracts to manage the exposure to unfavorable changes in the
cost of debt to be issued. These anticipatory hedges 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, 2003 or 2002.
Maintenance
- -----------
Maintenance costs are expensed as incurred. If it becomes probable that we will
recover specifically incurred costs through future rates a regulatory asset is
established to match the expensing of maintenance costs with their recovery in
cost-based regulated revenues.
Other Income and Other Expenses
- -------------------------------
Non-operational revenue including the nonregulated business activities of our
utilities, equity earnings of non-consolidated subsidiaries, gains on
dispositions of property, interest and dividends, AFUDC and miscellaneous
income, are reported in Other Income. Non-operational expenses including
nonregulated business activities of our utilities, losses on dispositions of
property, miscellaneous amortization, donations and various other non-operating
and miscellaneous expenses, are reported in Other Expenses.
AEP Consolidated Other Income and Deductions:
- ---------------------------------------------
December 31,
2003 2002 2001
------ ------ ------
(in millions)
Other Income:
- -------------
Equity Earnings (Loss) $ 10 $(15) $ 30
Non-operational Revenue 129 201 184
Interest 42 26 48
Gain on Sale of Frontera - - 73
Gain on Sale of REPs (Mutual Energy Companies) 39 129 -
Other 167 120 36
------ ------ ------
Total Other Income $387 $461 $371
====== ====== ======
Other Expenses:
- ---------------
Property Taxes $ 20 $ 20 $ 15
Non-operational Expenses 112 179 76
Fiber Optic and Datapult Exit Costs - - 49
Provision for Loss - Airplane - - 14
Other 95 124 71
------ ------ ------
Total Other Expenses $227 $323 $225
====== ====== ======
Income Taxes and Investment Tax Credits
- ---------------------------------------
We use the liability method of accounting for income taxes. Under the liability
method, deferred income taxes are provided for all temporary differences between
the book and tax basis of assets and liabilities which will result in a future
tax consequence.
When the flow-through method of accounting for temporary differences is
reflected in regulated revenues (that is, when 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 to match the regulated revenues and tax expense.
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
- ------------
We act as an agent for some state and local governments and collect from
customers certain excise taxes levied by those state or local governments on our
customer. We do not recognize these taxes as revenue or expense.
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 unless the debt is refinanced. If the reacquired 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 are generally deferred and amortized over the term of the replacement
debt consistent with its recovery in rates. We report gains and losses on the
reacquisition of debt for operations that are not subject to cost-based rate
regulation in Other Income and Other Expenses.
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 reflected in rates, redemption premiums paid to reacquire preferred stock
of certain 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
- ------------------------------
When we acquire businesses we record the fair value of any acquired goodwill and
other intangible assets. Purchased goodwill and intangible assets with
indefinite lives are not amortized. We test acquired goodwill and other
intangible assets with indefinite lives for impairment at least annually.
Intangible assets with finite lives are amortized over their respective
estimated lives to their estimated residual values.
The policies described above became effective with our adoption of a new
accounting standard for goodwill (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. Intangible assets with finite lives continue to be amortized over
their respective estimated lives ranging from 2 to 10 years.
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 have
established investment limitations and general risk management guidelines. In
general, limitations include:
. Acceptable investments (rated investment grade or above)
. Maximum percentage invested in a specific type of investment
. Prohibition of investment in obligations of the applicable company or
its affiliates
Trust funds are maintained for each regulatory jurisdiction and managed by
investment managers external to AEP, 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 Spent Nuclear Fuel and
Decommissioning Trusts for amounts relating to the Cook Plant and are included
in Assets Held for Sale for amounts relating to the Texas Plants. See "Assets
Held for Sale" section of Note 10 for further information regarding the Texas
Plants. These securities are recorded at market value. Securities in the trust
funds have been classified as available-for-sale due to their long-term purpose.
Unrealized gains and losses from securities in these trust funds are reported as
adjustments to the regulatory liability account for the nuclear decommissioning
trust funds and to regulatory assets or liabilities for the spent nuclear fuel
disposal trust funds in accordance with their treatment in rates.
Comprehensive Income (Loss)
- ---------------------------
Comprehensive income (loss) is defined as the change in equity (net assets) of a
business enterprise during a period from transactions and other events and
circumstances from non-owner sources. It includes all changes in equity during a
period except those resulting from investments by owners and distributions to
owners. Comprehensive income (loss) has two components: net income (loss) and
other comprehensive income (loss).
Components of Accumulated Other Comprehensive Income (Loss)
- -----------------------------------------------------------
Accumulated Other Comprehensive Income (Loss) is included on the balance sheet
in the equity section. The following table provides the components that
constitute the balance sheet amount in Accumulated Other Comprehensive Income
(Loss):
December 31,
----------------------------------
Components 2003 2002 2001
- ---------- ------ ------ ------
(in millions)
Foreign Currency Translation Adjustments $ 110 $ 4 $(113)
Unrealized Losses on Securities Available for Sale (1) (2) -
Unrealized Losses on Cash Flow Hedges (94) (16) (3)
Minimum Pension Liability (441) (595) (10)
------ ------ ------
Total $(426) $(609) $(126)
====== ====== ======
Stock Based Compensation Plans
- ------------------------------
At December 31, 2003, we have two stock-based employee compensation plans with
outstanding stock options, which are described more fully in Note 12. No stock
option expense is reflected in our 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.
We also grant performance share units, phantom stock units, restricted shares
and restricted stock units to employees, as well as stock units to non-employee
members of the Board of Directors. The Deferred Compensation and Stock Plan for
Non-Employee Directors permits directors to choose to defer up to 100 percent of
their annual Board retainer in stock units, and the Stock Unit Accumulation Plan
for Non-Employee Directors awards stock units to directors. Compensation cost is
included in Net Income for the performance share units, phantom stock units,
restricted shares, restricted stock units and the Director's stock units.
We do not currently intend to adopt the fair-value-based method of accounting
for stock options. The following table shows the effect on our Net Income (Loss)
and Earnings (Loss) per Share as if we had applied fair value measurement and
recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based
Compensation," to stock-based employee compensation awards:
Year Ended December 31,
------------------------------
2003 2002 2001
------ ------ ------
(in millions, except per share data)
Net Income (Loss), as reported $ 110 $ (519) $ 971
Add: Stock-based compensation expense included in
reported net income, net of related tax effects 2 (5) 3
Deduct: Stock-based employee compensation expense
determined under fair value based method for all
awards, net of related tax effects (7) (4) (15)
------ ------- ------
Pro Forma Net Income (Loss) $ 105 $ (528) $ 959
====== ======= ======
Earnings (Loss) per Share:
Basic - as Reported $0.29 $(1.57) $3.01
Basic - Pro Forma (a) $0.27 $(1.59) $2.98
Diluted - as Reported $0.29 $(1.57) $3.01
Diluted - Pro Forma (a) $0.27 $(1.59) $2.97
(a) The pro forma amounts are not representative of the effects on
reported net income for future years.
Earnings Per Share (EPS)
- ------------------------
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.
The calculation of our basic and diluted earnings (loss) per common share (EPS)
is based on weighted average common shares shown in the table below:
2003 2002 2001
------ ------ ------
(in millions - except per share amounts)
Weighted Average Shares:
Average Common Shares Outstanding 385 332 322
Assumed Conversion of Dilutive Stock Options (see Note 12) - - 1
--- --- ---
Diluted Average Common Shares Outstanding 385 332 323
=== === ===
The assumed conversion of stock options does not affect net earnings (loss) for
purposes of calculating diluted earnings per share. Our basic and diluted EPS
are the same in 2003, 2002 and 2001 since the effect on weighted average common
shares outstanding is minimal.
Had we reported 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 5.6 million, 8.8 million and 0.7 million shares of common
stock were outstanding at December 31, 2003, 2002 and 2001, 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 our common stock
exceeds $49.08 per share. There were no dilutive effects from equity units at
December 31, 2003 and 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 17.
Supplementary Information
- -------------------------
Year Ended December 31,
2003 2002 2001
---- ---- ----
(in millions)
AEP Consolidated Purchased Power -
Ohio Valley Electric Corporation (44.2% owned by AEP System) $147 $142 $127
Cash was paid for:
Interest (net of capitalized amounts) $741 $792 $972
Income Taxes $163 $336 $569
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $ 25 $ 6 $ 17
Assumption of Liabilities Related to Acquisitions $ - $ 1 $171
Increase in assets and liabilities resulting from:
Consolidation of VIEs due to the adoption of FIN 46 (see Note 2) $547 $ - $ -
Consolidation of merchant power generation facility (see Note 16) $496 $ - $ -
Exchange of Communication Investment for Common Stock $ - $ - $ 5
Power Projects
- --------------
We own interests of 50% or less in domestic unregulated power plants with a
capacity of 1,043 MW located in Colorado, Florida and Texas. In addition to the
domestic projects, we have interests of 50% or less in international power
plants totaling 1,113 MW (see Note 10, "Acquisitions, Dispositions, Discontinued
Operations, Impairments, Assets Held for Sale and Assets Held and Used").
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 our Consolidated Balance Sheets (see "Eastex" within the Dispositions section
of Note 10). At December 31, 2003, five domestic power projects and three
international power investments are accounted for under the equity method. The
five 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 $8 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits. In addition, AEP has
issued letters of credit with maximum future payments of $23 million for
domestic power projects and $69 million for international power investments.
Reclassifications
- -----------------
Certain prior period financial statement items have been reclassified to conform
to current period presentation. Such reclassifications had no impact on
previously reported Net Income (Loss).
2. NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF
ACCOUNTING CHANGES
- -------------------------------------------------------------------------------
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
SFAS 132 (revised 2003) "Employers' Disclosure about Pensions and Other
Postretirement Benefits"
- -----------------------------------------------------------------------
In December 2003 the FASB issued SFAS 132 (revised 2003), which requires
additional footnote disclosures about pensions and postretirement benefits, some
of which are effective beginning with the year-end 2003 financial statements.
Other additional disclosures will begin with our 2004 quarterly financial
statements or our 2004 year-end financial statements.
We will implement new quarterly disclosures when they become effective in the
first quarter of 2004, including (a) the amount of net periodic benefit cost for
each period for which an income statement is presented, showing separately each
component thereof, and (b) the amount of employer contributions paid and
expected to be paid during the current year, if significantly different from
amounts disclosed at the most recent year-end.
We will implement the new year-end disclosure when it becomes effective in the
fourth quarter of 2004, concerning information about foreign plans, if
appropriate. See Note 11 for these additional 2003 disclosures.
SFAS 142 "Goodwill and Other Intangible Assets"
- -----------------------------------------------
SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized, and that goodwill and intangible assets be tested
annually for impairment. The implementation of SFAS 142 resulted in a $350
million after tax net transitional loss in 2002 for the U.K. and Australian
operations and is reported in our Consolidated Statements of Operations as a
cumulative effect of accounting change. See Note 3 for further information on
goodwill and other intangible assets.
SFAS 143 "Accounting for Asset Retirement Obligations"
- ------------------------------------------------------
We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability at fair
value for any legal obligations for asset retirements in the period incurred.
Upon establishment of a legal liability, SFAS 143 requires a corresponding asset
to be established which will be depreciated over its useful life. SFAS 143
requires that a cumulative effect of change in accounting principle be
recognized for the cumulative accretion and accumulated depreciation that would
have been recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in accounting
principle is favorably affected by the reversal of accumulated removal cost.
These costs had previously been recorded for generation and did not qualify as a
legal obligation although these costs were collected in depreciation rates by
certain formerly regulated subsidiaries.
We completed a review of our asset retirement obligations and concluded that we
have related legal liabilities for nuclear decommissioning costs for our Cook
Plant and our partial ownership in the South Texas Project, as well as
liabilities for the retirement of certain ash ponds, wind farms, the U.K.
Plants, and certain coal mining facilities. Since we presently recover our
nuclear decommissioning costs in our regulated cash flow and have existing
balances recorded for such nuclear retirement obligations, we recognized the
cumulative difference between the amount already provided through rates and the
amount as measured by applying SFAS 143 as a regulatory asset or liability.
Similarly, a regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In 2003, we
recorded an unfavorable cumulative effect of $45.4 million after tax for our
non-regulated operations ($38.0 million related to Ash Ponds in the Utility
Operations segment, $7.2 million related to U.K. Plants in the Investments - UK
Operations segment and $0.2 million for Wind Mills in the Investments - Other
segment).
Certain of our utility operating companies have collected removal costs from
ratepayers for certain assets that do not have associated legal asset retirement
obligations. To the extent that operating companies have now been deregulated we
reversed the balance of such removal costs, totaling $287.2 million, after tax,
which resulted in a net favorable cumulative effect in 2003. We have
reclassified approximately $1.2 billion of removal costs for our utility
operations from accumulated depreciation to Regulatory Liabilities and Deferred
Investment Tax Credits in 2003 and to Deferred Credits and Other in 2002. In
addition, $9 million is classified as held-for-sale related to the TCC
generation assets as of December 31, 2003 and 2002.
The net favorable cumulative effect of the change in accounting principle for
the year ended December 31, 2003 consists of the following:
Pre-tax After-tax
Income (Loss) Income (Loss)
------------- -------------
(in millions)
Ash Ponds $(62.8) $(38.0)
U.K. Plants, Wind Mills and
Coal Operations (11.3) (7.4)
Reversal of Cost of Removal 472.6 287.2
------- -------
Total $398.5 $241.8
======= =======
We have identified, but not recognized, asset retirement obligation liabilities
related to electric transmission and distribution and gas pipeline assets, as a
result of certain easements on property on which we have assets. Generally, such
easements are perpetual and require only the retirement and removal of our
assets upon the cessation of the property's use. The retirement obligation is
not estimable for such easements since we plan to use our facilities
indefinitely. The retirement obligation would only be recognized if and when we
abandon or cease the use of specific easements.
The following is a reconciliation of the beginning and ending aggregate carrying
amount of asset retirement obligations:
U.K. Plants,
Wind Mills
Nuclear Ash and Coal
Decommissioning Ponds Operations Total
--------------- ----- ------------ -----
(in millions)
Asset Retirement Obligation Liability
at January 1, 2003 $ 718.3 $69.8 $ 37.2 $ 825.3
Accretion Expense 52.6 5.6 2.3 60.5
Liabilities Incurred - - 8.3 8.3
Foreign Currency Translation - - 5.3 5.3
------- ----- ------ -------
Asset Retirement Obligation
Liability at December 31, 2003
including Held for Sale 770.9 75.4 53.1 899.4
Less Asset Retirement Obligation
Liability Held for Sale:
South Texas Project (218.8) - - (218.8)
U.K. Plants - - (28.8) (28.8)
------- ----- ------ -------
Asset Retirement Obligation
Liability at December 31, 2003 $ 552.1 $75.4 $ 24.3 $ 651.8
======= ===== ====== =======
Accretion expense is included in Maintenance and Other Operation expense in our
accompanying Consolidated Statements of Operations.
As of December 31, 2003 and 2002, the fair value of assets that are legally
restricted for purposes of settling the nuclear decommissioning liabilities
totaled $845 million and $716 million, respectively, of which $720 million and
$618 million relating to the Cook Plant was recorded in Spent Nuclear Fuel and
Decommissioning Trusts in our Consolidated Balance Sheets. The fair value of
assets that are legally restricted for purposes of settling the nuclear
decommissioning liabilities for the South Texas Project totaling $125 million
and $98 million as of December 31, 2003 and 2002, respectively, was classified
as Assets Held for Sale in our Consolidated Balance Sheets.
Pro forma net income and earnings per share are not presented for the years
ended December 31, 2002 and 2001 because the pro forma application of SFAS 143
would result in pro forma net income and earnings per share not materially
different from the actual amounts reported during those periods.
As of December 31, 2002 and 2001, the pro forma liability for asset retirement
obligations which has been calculated as if SFAS 143 had been adopted at the
beginning of each period was $825 million and $769 million, respectively.
SFAS 144 "Accounting for the Impairment or Disposal of Long-lived Assets"
- -------------------------------------------------------------------------
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." We adopted SFAS
144 effective January 1, 2002. See Note 10 for discussion of impairments
recognized in 2003 and 2002.
SFAS 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and Technical Corrections"
- ---------------------------------------------------------------------------
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). 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, we reclassified
Extraordinary Losses (Net of Tax) on TCC's reacquired debt of $2 million for
2001 to Other Expenses.
SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities"
- ---------------------------------------------------------------------------
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 time at which we recognize future costs related to
exit or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. We adopted the provisions of SFAS 146
for exit or disposal activities initiated after December 31, 2002.
SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
- --------------------------------------------------------------------------
On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149
amends SFAS 133 to clarify the definition of a derivative and the requirements
for contracts to qualify for the normal purchase and sale exemption. SFAS 149
also amends certain other existing pronouncements. Effective July 1, 2003, we
implemented SFAS 149 and the effect was not material to our results of
operations, cash flows or financial condition.
SFAS 150 "Accounting for Certain Financial Instruments with Characteristics of
Both Liabilities and Equity"
- ------------------------------------------------------------------------------
We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the first phase of
the FASB's project to eliminate from the balance sheet the "mezzanine"
presentation of items with characteristics of both liabilities and equity,
including: (1) mandatorily redeemable shares, (2) instruments other than shares
that could require the issuer to buy back some of its shares in exchange for
cash or other assets and (3) certain obligations that can be settled with
shares. Measurement of these liabilities generally is to be at fair value, with
the payment or accrual of "dividends" and other amounts to holders reported as
interest cost.
Beginning with our third quarter 2003 financial statements, we present
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as a
Non-Current Liability. Beginning July 1, 2003, we classify dividends on these
mandatorily redeemable preferred shares as interest expense. In accordance with
SFAS 150, dividends from prior periods remain classified as preferred stock
dividends (a component of Preferred Stock Dividend Requirements of
Subsidiaries).
FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
- --------------------------------------------------------------------------
In November 2002, the FASB issued FIN 45 which clarifies the accounting to
recognize liabilities related to issuing a guarantee, as well as additional
disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the
effect was not material to our results of operations, cash flows or financial
condition. See Note 8 for further disclosures.
FIN 46 (revised December 2003)"Consolidation of Variable Interest Entities" and
FIN 46 "Consolidation of Variable Interest Entities"
- -------------------------------------------------------------------------------
We implemented FIN 46, "Consolidation of Variable Interest Entities," effective
July 1, 2003. FIN 46 interprets the application of Accounting Research Bulletin
No. 51, "Consolidated Financial Statements," to 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. Due to the
prospective application of FIN 46, we did not reclassify prior period amounts.
On July 1, 2003, we deconsolidated Caddis Partners, LLC (Caddis). At December
31, 2002 $759 million was reported as a Minority Interest in Finance Subsidiary.
At December 31, 2003 $527 million is reported as a note payable to Caddis, a
component of Long-Term Debt. See Note 17 "Financing Activities" for further
disclosures.
On July 1, 2003, we also deconsolidated the trusts which hold mandatorily
redeemable trust preferred securities. Therefore, of the $321 million net amount
reported as "Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred
Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of
Such Subsidiaries" at December 31, 2002, $331 million is reported as Notes
Payable to Trust (included in Long-term Debt) and $10 million is reported in
Other Non-Current Assets at December 31, 2003.
Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company (Sabine), a
contract mining operation providing mining services to SWEPCo. Upon
consolidation, SWEPCo recorded the assets and liabilities of Sabine ($77.8
million). Also, after consolidation, SWEPCo currently records all expenses
(depreciation, interest and other operation expense) of Sabine and eliminates
Sabine's revenues against SWEPCo's fuel expenses. There is no cumulative effect
of accounting change recorded as a result of our requirement to consolidate, and
there is no change in net income due to the consolidation of Sabine.
Effective July 1, 2003, OPCo consolidated JMG. Upon consolidation, OPCo recorded
the assets and liabilities of JMG ($469.6 million). OPCo now records the
depreciation, interest and other operating expenses of JMG and eliminates JMG's
revenues against OPCo's operating lease expenses. There is no cumulative effect
of accounting change recorded as a result of our requirement to consolidate JMG,
and there is no change in net income due to the consolidation of JMG. See Note
16 "Leases" for further disclosures.
In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN 46R)
which replaces FIN 46. The FASB and other accounting constituencies continue to
interpret the application of FIN 46R. As a result, we are continuing to review
the application of this new interpretation and expect to adopt FIN 46R by March
31, 2004.
EITF 02-3 and Rescission of EITF 98-10
- --------------------------------------
In October 2002, the Emerging Issues Task Force of the FASB reached a final
consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and related
interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded
for risk management contracts that are not derivatives pursuant to SFAS 133. The
consensus to rescind EITF 98-10 also eliminated the recognition of physical
inventories at fair value other than as provided by GAAP. We have implemented
this standard for all physical inventory and non-derivative risk management
transactions occurring on or after October 25, 2002. For physical inventory and
non-derivative risk management transactions entered into prior to October 25,
2002, we implemented this standard on January 1, 2003 and reported the effects
of implementation as a cumulative effect of an accounting change. We recorded a
$49 million loss, net of income tax, as a cumulative effect of accounting
change.
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 risk management
purposes. Previous guidance in EITF 98-10 permitted contracts that were not
settled financially 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 risk management contracts as revenues; we also recorded and
reported purchases under forward risk management contracts as purchased energy
expenses. Effective July 1, 2002, we reclassified such forward risk management
revenues and purchases on a net basis. The reclassification of such risk
management activities 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.
EITF 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That
Are Subject to FASB Statement No. 133 and Not "Held for Trading Purposes" as
Defined in Issue No. 02-3"
- ------------------------------------------------------------------------------
In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus
states that realized gains and losses on derivative contracts not "held for
trading purposes" should be reported either on a net or gross basis based on the
relevant facts and circumstances. Reclassification of prior year amounts is not
required. The adoption of EITF 03-11 did not have a material impact on our
results of operations, financial position or cash flows.
FASB Staff Position No. 106-1, Accounting and Disclosure Requirements Related to
the Medicare Prescription Drug Improvement and Modernization Act of 2003
- --------------------------------------------------------------------------------
On January 12, 2004, the FASB Staff issued FSP 106-1, which allows a one-time
election to defer accounting for any effects of the prescription drug subsidy
under the Medicare Prescription Drug Improvement and Modernization Act of 2003
(the Act), enacted on December 8, 2003. There are significant uncertainties as
to whether our plan will be eligible for a subsidy under future federal
regulations that have not yet been drafted. The method of accounting for any
such subsidy and, therefore, the subsidy's possible reduction to our accumulated
postretirement benefit obligation and periodic postretirement benefit costs has
not been resolved by the FASB or other professional accounting standard setting
authority. Accordingly, we elected to defer any potential effects of the Act
until authoritative guidance on the accounting for the federal subsidy is
issued. Our measurements of the accumulated postretirement benefit obligation
and periodic postretirement benefit cost included in these financial statements
do not reflect any potential effects of the Act. We cannot determine what
impact, if any, new authoritative guidance on the accounting for the federal
subsidy may have on our results of operations or financial condition.
Future Accounting Changes
- -------------------------
The FASB's standard-setting process is ongoing. Until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting of
our operations that may result from any such future changes.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
- ---------------------------------------
Accounting for Risk Management Contracts
- ----------------------------------------
EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. We recorded a
$49 million after tax charge against net income as Accounting for Risk
Management Contracts in our Consolidated Statements of Operations in Cumulative
Effect of Accounting Changes in the first quarter of 2003 ($12 million in
Utility Operations, $22 million in Investments - Gas Operations and $15 million
in Investments - UK Operations segments). This amount will be realized when the
positions settle.
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.
The effect of initially adopting the DIG guidance at July 1, 2001 was a
favorable earnings mark-to-market after tax effect of $18 million (net of tax of
$2 million). It was reported as a cumulative effect of an accounting change on
our Consolidated Statements of Operations (included in Investments-Other
segment).
Asset Retirement Obligations (SFAS 143)
- ---------------------------------------
In the first quarter of 2003, we recorded $242 million in after-tax income as a
cumulative effect of accounting change for Asset Retirement Obligations.
Goodwill and Other Intangible Assets
- ------------------------------------
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 in 2002 resulted in a $350 million net transitional
loss for our U.K. and Australian operations (included in the Investments - Other
segment) and is reported in our Consolidated Statements of Operations as a
cumulative effect of accounting change (see Note 3, "Goodwill and Other
Intangible Assets" for further details).
See table below for details of the Cumulative Effect of Accounting Changes:
Year Ended December 31,
----------------------------
Description 2003 2002 2001
- ----------- ---- ---- ----
(in millions)
Accounting for Risk Management Contracts (EITF 02-3) $(49) $ - $ -
Asset Retirement Obligations (SFAS 143) 242 - -
Goodwill and Other Intangible Assets - (350) -
Accounting for Risk Management Contracts (DIG Guidance) - - 18
----- ------ ----
Total $193 $(350) $18
===== ====== ====
EXTRAORDINARY ITEMS
- -------------------
In 2001, we recorded an extraordinary item for the discontinuance of regulatory
accounting under SFAS 71 for the generation portion of our business in the Ohio
state jurisdiction. OPCo and CSPCo recognized an extraordinary loss of $48
million (net of tax of $20 million) for unrecoverable Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits. 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.
3. GOODWILL AND OTHER INTANGIBLE ASSETS
- ----------------------------------------
GOODWILL
- --------
The changes in our carrying amount of goodwill for the years ended December 31,
2003 and 2002 by operating segment are:
Investments
---------------------------------------
Utility Gas UK AEP
Operations Operations Operations Other Consolidated
---------- ------------ ---------- ----- ------------
(in millions)
Balance at January 1, 2002
(including Assets Held for Sale) $37.1 $ 340.1 $ - $ 14.9 $ 392.1
Goodwill acquired - - 2.3 - 2.3
Changes to Goodwill due to
Purchase price adjustments - (33.8) 172.5 42.4 181.1
Impairment losses - - (170.0) (15.9) (185.9)
Foreign currency exchange rate changes - - 6.4 - 6.4
----- -------- -------- ------- --------
Balance at December 31, 2002
(including Assets Held for Sale) 37.1 306.3 11.2 41.4 396.0
Less: Assets Held for Sale, Net (a) - (143.8) (11.2) - (155.0)
----- -------- -------- ------- --------
Balance at December 31, 2002
(excluding Assets Held for Sale) $37.1 $ 162.5 $ - $ 41.4 $ 241.0
===== ======= ======== ======= ========
Balance at January 1, 2003
(including Assets Held for Sale) $37.1 $ 306.3 $ 11.2 $ 41.4 $ 396.0
Impairment losses - (291.4) (12.2) - (303.6)
Foreign currency exchange rate changes - - 1.0 - 1.0
----- -------- -------- ------- --------
Balance at December 31, 2003
(including Assets Held for Sale) 37.1 14.9 - 41.4 93.4
Less: Assets Held for Sale, Net (a) - (14.9) - - (14.9)
----- -------- -------- ------- --------
Balance at December 31, 2003
(excluding Assets Held for Sale) $37.1 $ - $ - $ 41.4 $ 78.5
===== ======== ======== ======= =======
(a) On our Consolidated Balance Sheets, amounts related to entities
classified as held for sale are excluded from Goodwill and are reported
within Assets Held for Sale (see Note 10). The following entities
classified as held for sale had goodwill or goodwill impairments during
the years ended December 31, 2003 or 2002:
. Jefferson Island (Investments - Gas Operations segment) - $14.4 million
and $143.3 million balances in goodwill at December 1, 2003 and 2002,
respectively. During 2003, we recognized a goodwill impairment loss of
$128.9 million.
. LIG Chemical (Investments - Gas Operations segment) - $0.5 million
balance in goodwill at December 31, 2003 and 2002.
. U.K. Coal Trading (Investments - UK Operations segment) - $11.2 million
balance in goodwill at December 31, 2002. In 2003, we recognized a
goodwill impairment loss of $12.2 million related to the impairment
study (impairment in 2003 was greater than December 31, 2002 balance due
to changes in foreign currency translation rates).
. U.K. Generation (Investments - UK Operations segment) - No goodwill
balances at December 31, 2003 or 2002. In 2002, we recognized a goodwill
impairment loss of $166.0 million related to the impairment study.
. AEP Coal (Investments - Other segment) - No goodwill balances at
December 31, 2003 or 2002. In 2002, we recognized a $3.6 million
impairment loss related to the impairment study.
Accumulated amortization of goodwill was approximately $1 million and $9 million
at December 31, 2003 and 2002, respectively. The decrease of $8 million between
years is related to the impairment of goodwill on Houston Pipe Line Company and
AEP Energy Services.
In the fourth quarter of 2003, we prepared our annual goodwill impairment tests.
The fair values of the operations were estimated using cash flow projections and
other market value indicators. As a result of the tests, we recognized a $162.5
million goodwill impairment loss related to Houston Pipe Line Company ($150.4
million) and AEP Energy Services ($12.1 million).
During 2002, changes to goodwill were due to purchase price adjustments of $6.7
million primarily related to our acquisition of Houston Pipe Line Company, MEMCO
and Nordic Trading (see Note 10).
In the first quarter of 2002, we recognized a goodwill impairment loss of $12.3
million for all goodwill related to Gas Power Systems (see Note 10).
In the fourth quarter of 2002, we prepared our annual goodwill impairment tests.
The fair values of the operations were estimated using cash flow projections. As
a result of the tests, we recognized a goodwill impairment loss of $4.0 million
related to Nordic Trading (see Note 10).
The transitional impairment loss related to SEEBOARD and CitiPower goodwill,
which is reported as Cumulative Effect of Accounting Changes in 2002, is
excluded from the above schedule.
The following tables show the transitional disclosures to adjust our 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,
- ----------------- ----------------------------------
2003 2002 2001
---- ---- ----
(in millions)
Reported Net Income (Loss) $110 $(519) $ 971
Add back: Goodwill amortization - - 39(a)
Add back: Amortization for intangibles with
indefinite lives - - 8(b)
----- ------ -------
Adjusted Net Income (Loss) $110 $(519) $1,018
===== ====== =======
Earnings (Loss) Per Share (Basic and Dilutive) Year Ended December 31,
- ---------------------------------------------- ----------------------------------
2003 2002 2001
---- ---- ----
Reported Earnings (Loss) per Share $0.29 $(1.57) $3.01
Add back: Goodwill amortization - - 0.12(c)
Add back: Amortization for intangibles with
indefinite lives - - 0.02(b)
----- ------- ------
Adjusted Earnings (Loss) per Share $0.29 $(1.57) $3.15
===== ======= ======
(a) This amount includes $34 million in 2001 related to SEEBOARD and CitiPower
amortization expense included in Discontinued Operations on our
Consolidated Statements of Operations.
(b) The amounts shown for 2001 relate to CitiPower amortization expense
included in Discontinued Operations on our Consolidated Statements of
Operations.
(c) This amount includes $0.10 in 2001 related to SEEBOARD and CitiPower
amortization expense included in Discontinued Operations on our
Consolidated Statements of Operations.
OTHER INTANGIBLE ASSETS
- -----------------------
Acquired intangible assets subject to amortization are $34 million at December
31, 2003 and $37 million at December 31, 2002, net of accumulated amortization.
The gross carrying amount, accumulated amortization and amortization life by
major asset class are:
December 31, 2003 December 31, 2002
--------------------------- ----------------------
Gross Gross
Amortization Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------ -------- ------------ -------- ------------
(in years) (in millions) (in millions)
Software and customer list (a) 2 $ - $ - $ 0.5 $0.2
Software acquired (b) 3 0.5 0.3 0.5 -
Patent 5 0.1 - 0.1 -
Easements 10 2.2 0.3 - -
Trade name and administration of
contracts 7 2.4 0.9 2.4 0.6
Purchased technology 10 10.9 2.2 10.3 1.0
Advanced royalties 10 29.4 7.7 29.4 4.7
----- ----- ----- ----
Total $45.5 $11.4 $43.2 $6.5
===== ===== ===== ====
(a) This asset was disposed of in the second quarter of 2003.
(b) This asset relates to U.K. Generation Plants and is included in Assets Held
for Sale on our Consolidated Balance Sheets.
Amortization of intangible assets was $5 million and $4 million for the twelve
months ended December 31, 2003 and 2002, respectively. Our estimated aggregate
amortization expense is $5 million for each year 2004 through 2007, $4 million
for 2008 through 2010 and $3 million in 2011.
4. RATE MATTERS
- ----------------
In certain jurisdictions, we have agreed to base rate or fuel recovery
limitations usually under terms of settlement agreements. See Note 5 for a
discussion of those terms related to Nuclear Plant Restart and Merger with CSW.
Fuel in SPP Area of Texas
- -------------------------
In 2001, the PUCT delayed the start of customer choice in the SPP area of Texas.
In May 2003, the PUCT ordered that competition would not begin in the SPP areas
before January 1, 2007. TNC filed with the PUCT in 2002 to determine the most
appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the
PUCT issued an order adopting the methodology proposed in TNC's filing, with
adjustments, for reconciling fuel costs in the SPP area. The adjustments removed
$3.71 per MWH from reconcilable fuel expense. This adjustment will reduce
revenues received by Mutual Energy SWEPCo who now serves TNC's SPP customers by
approximately $400,000 annually. In October 2003, Mutual Energy SWEPCo agreed
with the PUCT staff and the Office of Public Utility Counsel (OPC) to file a
fuel reconciliation proceeding for the period January 2002 through December 2003
by March 31, 2004 and the PUCT ordered that the filing be made.
TNC Fuel Reconciliations
- ------------------------
In June 2002, TNC filed with the PUCT to reconcile fuel costs, requesting 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
deferred 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 for
under-recovered fuel costs. TNC's SPP customers will continue to be subject to
fuel reconciliations until competition begins in the SPP area as described
above. The under-recovery balance at December 31, 2001 for TNC's service within
SPP was $0.7 million including interest.
In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD)
with a recommendation that TNC's under-recovered retail fuel balance be reduced.
In March 2003, TNC established a reserve of $13 million based on the
recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain
matters and remanded TNC's final fuel reconciliation to the ALJ to consider two
issues. The issues are the sharing of off-system sales margins from AEP's
trading activities with customers for five years per the PUCT's interpretation
of the Texas AEP/CSW merger settlement and the inclusion of January 2002 fuel
factor revenues and associated costs in the determination of the under-recovery.
The PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the final fuel
reconciliation proceeding. This would result in the sharing of margins for an
additional three and one half years after the end of the Texas ERCOT fuel
factor.
On December 3, 2003, the ALJ issued a PFD in the remand phase of the TNC fuel
reconciliation recommending additional disallowances for the two remand issues.
TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel
reconciliation proceeding on January 15, 2004 accepting the PFD. TNC is waiting
for a written order, after which it will request a rehearing of the PUCT's
ruling. While management believes that the Texas merger settlement only provided
for sharing of margins during the period fuel and generation costs were
regulated by the PUCT, an additional provision of $10 million was recorded in
December 2003. Based on the decisions of the PUCT, TNC's final under-recovery
including interest at December 31, 2003 was $6.2 million.
In February 2002, TNC received a final order from the PUCT in a previous fuel
reconciliation covering the period July 1997 to June 2000 and reflected the
order in its financial statements. This final order was appealed to the Travis
County District Court. In May 2003, the District Court upheld the PUCT's final
order. That order is currently on appeal to the Third Court of Appeals.
TCC Fuel Reconciliation
- -----------------------
In December 2002, TCC filed its final fuel reconciliation with the PUCT to
reconcile fuel costs to be included in its deferred over-recovery balance in the
2004 true-up proceeding. This reconciliation covers the period of July 1998
through December 2001. 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.
Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC
established a reserve for potential adverse rulings of $81 million during 2003.
In July 2003, the ALJ requested that additional information be provided in the
TCC fuel reconciliation related to the impact of the TNC orders, referenced
above, on TCC. On February 3, 2004, the ALJ issued a PFD recommending that the
PUCT disallow $140 million in eligible fuel costs including some new items not
considered in the TNC case, and other items considered but not disallowed in the
TNC ruling. At this time, management is unable to predict the outcome of this
proceeding. An adverse ruling from the PUCT, disallowing amounts in excess of
the established reserve 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 6 "Customer Choice and
Industry Restructuring."
SWEPCo Texas Fuel Reconciliation
- --------------------------------
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This
reconciliation covers the period of January 2000 through December 2002. At
December 31, 2002, SWEPCo's filing included a $2 million deferred over-recovery
balance including interest. During the reconciliation period, SWEPCo incurred
$435 million of Texas retail eligible fuel expense. In November 2003,
intervenors and the PUCT Staff recommended fuel cost disallowances of more than
$30 million. In December 2003, SWEPCo agreed to a settlement in principle with
all parties in the fuel reconciliation. The settlement provides for a
disallowance in fuel costs of $8 million which was recorded in December 2003. In
addition, the settlement provides for the deferral as a regulatory asset of
costs of a new lignite mining agreement in excess of a specified benchmark for
lignite at SWEPCo's Dolet Hills Plant. The settlement provides for recovery of
the deferred costs over a period ending in April 2011 as cost savings are
realized under the new mining agreement. The settlement also will allow future
recovery of litigation costs associated with the termination of a previous
lignite mining agreement if future costs savings are adequate. The settlement
will be filed with the PUCT for approval.
ERCOT Price-to-Beat (PTB) Fuel Factor Appeal
- --------------------------------------------
Several parties including the Office of Public Utility Counsel (OPC) and cities
served by both TCC and TNC appealed the PUCT's December 2001 orders establishing
initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. On June
25, 2003, the District Court ruled in both appeals. The Court ruled in the
Mutual Energy WTU case that the PUCT lacked sufficient evidence to include
unaccounted for energy in the fuel factor, and that the PUCT improperly shifted
the burden of proof and the record lacked substantial evidence on the effect of
loss of load due to retail competition on generation requirements. The Court
upheld the initial PTB orders on all other issues. In the Mutual Energy CPL
proceeding, the Court ruled that the PUCT improperly shifted the burden of proof
and the record lacked substantial evidence on the effect of loss of load due to
retail competition on generation requirements. The amount of unaccounted for
energy built into the PTB fuel factors was approximately $2.7 million for Mutual
Energy WTU. At this time, management is unable to estimate the potential
financial impact related to the loss of load issue. The District Court decision
was appealed to the Third Court of Appeals by Mutual Energy CPL, Mutual Energy
WTU and other parties. Management believes, based on the advice of counsel, that
the PUCT's original decision will ultimately be upheld. If the District Court's
decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors
charged to retail customers in 2002 and 2003 resulting in an adverse effect on
future results of operations and cash flows.
Unbundled Cost of Service (UCOS) Appeal
- ---------------------------------------
The UCOS proceeding established the regulated wires rates to be effective when
retail electric competition began. TCC placed new transmission and distribution
rates into effect as of January 1, 2002 based upon an order issued by the PUCT
resulting from TCC's UCOS proceeding. TCC requested and received approval from
the FERC of wholesale transmission rates determined in the UCOS proceeding.
Regulated delivery charges include the retail transmission and distribution
charge and, among other items, a nuclear decommissioning fund charge, a
municipal franchise fee, a system benefit fund fee, a transition charge
associated with securitization of regulatory assets and a credit for excess
earnings. Certain rulings of the PUCT in the UCOS proceeding, including the
initial determination of stranded costs, the requirement to refund TCC's excess
earnings, regulatory treatment of nuclear insurance and distribution rates
charged municipal customers, were appealed to the Travis County District Court
by TCC and other parties to the proceeding. The District Court issued a decision
on June 16, 2003, upholding the PUCT's UCOS order with one exception. The Court
ruled that the refund of the 1999 through 2001 excess earnings, solely as a
credit to non-bypassable transmission and distribution rates charged to REPs,
discriminates against residential and small commercial customers and is
unlawful. The distribution rate credit began in January 2002. This decision
could potentially affect the PTB rates charged by Mutual Energy CPL and could
result in a refund to certain of its customers. Mutual Energy CPL was a
subsidiary of AEP until December 23, 2002 when it was sold. Management estimates
that the effect of a decision to reduce the PTB rates for the period prior to
the sale is approximately $11 million pre-tax. The District Court decision was
appealed to the Third Court of Appeals by TCC and other parties. Based on advice
of counsel, management believes that it will ultimately prevail on appeal. If
the District Court's decision is ultimately upheld on appeal or the Court of
Appeals reverses the District Court on issues adverse to TCC, it could have an
adverse effect on future results of operations and cash flows.
TCC Rate Case
- -------------
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates should not be
reduced. Other municipalities served by TCC passed similar rate review
resolutions. In Texas, municipalities have original jurisdiction over rates of
electric utilities within their municipal limits. Under Texas law, TCC must
provide support for its rates to the municipalities. TCC filed the requested
support for its rates based on a test year ending June 30, 2003 with all of its
municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease
its wholesale transmission rates by $2 million or 2.5% and increase its retail
energy delivery rates by $69 million or 19.2%. On February 9, 2004, eight
intervening parties filed testimony recommending reductions to TCC's requested
$67 million rate increase. The recommendations range from a decrease in existing
rates of approximately $100 million to an increase in TCC's current rates of
approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004,
recommending reductions to TCC's request of approximately $51 million. TCC's
rebuttal testimony was filed on February 26, 2004. Hearings are scheduled for
March 2004 with a PUCT decision expected in May 2004. Management is unable to
predict the ultimate effect of this proceeding on TCC's rates or its impact on
TCC's results of operations, cash flows and financial condition.
Louisiana Fuel Audit
- --------------------
The LPSC is performing an audit of SWEPCo's historical fuel costs. In addition,
five SWEPCo customers filed a suit in the Caddo Parish District Court in January
2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has
over charged them for fuel costs since 1975. The LPSC consolidated the customer
complaint and audit. In January 2004, a procedural schedule was issued requiring
LPSC Staff and intervenor testimony to be filed in June 2004 and scheduling
hearings for October 2004. Management believes that SWEPCo's fuel costs were
proper and those costs incurred prior to 1999 have been approved by the LPSC.
Management is unable to predict the outcome of these proceedings. If the actions
of the LPSC or the Court result in a material disallowance of recovery of
SWEPCo's fuel costs from customers, it could have an adverse impact on results
of operations and cash flows.
Louisiana Compliance Filing
- ---------------------------
In October 2002, SWEPCo filed with the 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. In 2004 the
LPSC required SWEPCo to file updated financial information with a test year
ending December 31, 2003 before April 16, 2004. If, after review of the updated
information, 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 Wholesale Fuel Complaints
- ------------------------------
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 since 1997.
Negotiations to settle the complaint and update the contracts resulted in new
contracts. The FERC approved an offer of settlement regarding the fuel complaint
and new contracts at market prices in December 2003. Since TNC had recorded a
provision for refund in 2002, the effect of the settlement was a $4 million
favorable adjustment recorded in December 2003.
Environmental Surcharge Filing
- ------------------------------
In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million) to
recover the cost of emissions control equipment being installed at the Big Sandy
Plant. See NOx Reductions in Note 7.
In March 2003, the KPSC granted approximately $18 million of the request. Annual
rate relief of $1.7 million became effective in May 2003 and an additional $16.2
million became effective in July 2003. The recovery of such amounts is intended
to offset KPCo's cost of compliance with the Clean Air Act.
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. In October 2003, PSO
filed financial information and supporting testimony in response to the OCC's
requirements. PSO's response indicates that its annual revenues are $36 million
less than costs. As a result, PSO is seeking OCC approval to increase its base
rates by that amount, which is a 3.6% increase over PSO's existing revenues.
Hearings are scheduled for October 2004. Management is unable to predict the
ultimate effect of this review on PSO's rates or its impact on PSO's results of
operations, cash flows and financial condition.
PSO Fuel and Purchased Power
- ----------------------------
PSO had a $44 million under-recovery of fuel costs resulting from a 2002
reallocation among AEP West companies of purchased power costs for periods prior
to January 1, 2002. In July 2003, PSO filed with the OCC seeking recovery of the
$44 million over an 18-month time period. In August 2003, the OCC Staff filed
testimony recommending PSO be granted recovery of $42.4 million over three
years. In September 2003, the OCC expanded the case to include a full review of
PSO's 2001 fuel and purchased power practices. PSO filed its testimony in
February 2004 and hearings will occur in June 2004. If the OCC determines as a
result of the review that a portion of PSO's fuel and purchased power costs
should not be recovered, there will be an adverse effect on PSO's results of
operations, cash flows and possibly financial condition.
Virginia Fuel Factor Filing
- ---------------------------
APCo filed with the Virginia SCC to reduce its fuel factor effective August 1,
2003. The requested fuel rate reduction was approved by the Virginia SCC and is
effective for 17 months (August 1, 2003 to December 31, 2004) and is estimated
to reduce revenues by $36 million during that period. This fuel factor
adjustment will reduce cash flows without impacting results of operations as any
over-recovery or under-recovery of fuel costs would be deferred as a regulatory
liability or a regulatory asset.
FERC Long-term Contracts
- ------------------------
In 2002, the FERC set for hearing complaints filed by certain wholesale
customers located in Nevada and Washington that sought to break long-term
contracts which the customers alleged were "high-priced." At issue were
long-term contracts entered into during the California energy price spike in
2000 and 2001. The complaints alleged that AEP sold power at unjust and
unreasonable prices.
In February 2003, AEP and one of the customers agreed to terminate their
contract. The customer withdrew its FERC complaint and paid $59 million to AEP.
As a result of the contract termination, AEP reversed $69 million of unrealized
mark-to-market gains previously recorded, resulting in a $10 million pre-tax
loss.
In December 2002, a FERC ALJ ruled in favor of AEP and dismissed a complaint
filed by two Nevada utilities. In 2000 and 2001, we agreed to sell power to the
utilities for future delivery. In 2001, the utilities filed complaints asserting
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 executed. 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. In June 2003, the FERC issued an order affirming the ALJ's
decision. The utilities requested a rehearing which the FERC denied. The
utilities' appeal of the FERC order is pending before the U.S. Court of Appeals
for the Ninth Circuit. Management is unable to predict the outcome of this
proceeding and its impact on future results of operations and cash flows.
RTO Formation/Integration Costs
- -------------------------------
With FERC approval, AEP East companies have been deferring costs incurred under
FERC orders to form an RTO (the Alliance RTO) or join an existing RTO (PJM). In
July 2003, the FERC issued an order approving our continued deferral of both our
Alliance formation costs and our PJM integration costs including the deferral of
a carrying charge. The AEP East companies have deferred approximately $28
million of RTO formation and integration costs and related carrying charges
through December 31, 2003. As a result of the subsequent delay in the
integration of AEP's East transmission system into PJM, FERC declined to rule,
in its July order, on our request to transfer the deferrals to regulatory
assets, and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies will apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration with PJM.
In August 2003, the Virginia SCC filed a request for rehearing of the July
order, arguing that FERC's action was an infringement on state jurisdiction, and
that FERC should not have treated Alliance RTO startup costs in the same manner
as PJM integration costs. On October 22, 2003, FERC denied the rehearing
In its July 2003 order, FERC indicated that it would review the deferred costs
at the time they are transferred to a regulatory asset account and scheduled for
amortization and recovery in the open access transmission tariff (OATT) to be
charged by PJM. Management believes that the FERC will grant permission for the
deferred RTO costs to be amortized and included in the OATT. Whether the
amortized costs will be fully recoverable depends upon the state regulatory
commissions' treatment of AEP East companies' portion of the OATT at the time
they join PJM. Presently, retail base rates are frozen or capped and cannot be
increased for retail customers of CSPCo, I&M and OPCo. APCo's Virginia retail
base rates are capped with an opportunity for a one-time increase in
non-generation rates after January 1, 2004. We intend to file an application
with FERC seeking permission to delay the amortization of the deferred RTO
formation/integration costs until they are recoverable from all users of the
transmission system including retail customers. Management is unable to predict
the timing of when AEP will join PJM and if upon joining PJM whether FERC will
grant a delay of recovery until the rate caps and freezes end. If the AEP East
companies do not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently estimated at
$24 million for the entire PJM integration project). Management intends to seek
recovery of the deferred RTO formation/integration costs and project
implementation cost reimbursements, if incurred. If the FERC ultimately decides
not to approve a delay or the state commissions deny recovery, future results of
operations and cash flows could be adversely affected.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only
with the approval of the Virginia SCC, but required such transfers by January 1,
2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study
covering the time period through 2014 as required by the Virginia SCC. The study
results show a net benefit of approximately $98 million for APCo over the
11-year study period from AEP's participation in PJM.
In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In August 2003,
KPCo sought and was granted a rehearing to submit additional evidence. In
December 2003, AEP filed with the KPSC a cost/benefit study showing a net
benefit of approximately $13 million for KPCo over the five-year study period
from AEP's participation in PJM. A hearing has been scheduled in April 2004.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to certain
conditions included in the order. The IURC's order stated that AEP shall request
and the IURC shall complete a review of Alliance formation costs before any
deferral of the costs for future recovery.
In November 2003, the FERC issued an order preliminarily finding that AEP must
fulfill its CSW merger condition to join an RTO by integrating into PJM
(transmission and markets) by October 1, 2004. The order was based on PURPA
205(a), which allows FERC to exempt electric utilities from state law or
regulation in certain circumstances. The FERC set for public hearing before an
ALJ several issues. Those issues include whether the laws, rules, or regulations
of Virginia and Kentucky are preventing AEP from joining an RTO and whether the
exceptions under PURPA apply. The FERC directed the ALJ to issue his initial
decision by March 15, 2004.
FERC Order on Regional Through and Out Rates
- --------------------------------------------
In July 2003, the FERC issued an order directing PJM and the Midwest ISO to make
compliance filings for their respective Open Access Transmission Tariffs to
eliminate, by November 1, 2003, the transaction-based charges for through and
out (T&O) transmission service on transactions where the energy is delivered
within the proposed Midwest ISO and PJM expanded regions (RTO Footprint). In
October 2003, the FERC postponed the November 1, 2003 deadline to eliminate T&O
rates. The elimination of the T&O rates will reduce the transmission service
revenues collected by the RTOs and thereby reduce the revenues received by
transmission owners under the RTOs' revenue distribution protocols. The order
provided that affected transmission owners could file to offset the elimination
of these revenues by increasing rates or utilizing a transitional rate mechanism
to recover lost revenues that result from the elimination of the T&O rates. The
FERC also found that the T&O rates of some of the former Alliance RTO companies,
including AEP, may be unjust, unreasonable, and unduly discriminatory or
preferential for energy delivered in the RTO Footprint. FERC initiated an
investigation and hearing in regard to these rates. We made a filing with the
FERC to support the justness and reasonableness of our rates. We also made a
joint filing with unaffiliated utilities proposing a regional revenue
replacement mechanism for the lost revenues, in the event that FERC eliminated
all T&O rates for delivery points within the RTO Footprint. In orders issued in
November 2003, the FERC dismissed the joint filing, but adopted a new regional
rate design substantially in the form proposed in the joint filing. The orders
directed each transmission provider to file compliance rates to eliminate T&O
rates prospectively within the region and simultaneously implement new seams
elimination cost allocation (SECA) rates to mitigate the lost revenues for a
two-year transition period beginning April 1, 2004. The FERC did not indicate
the recovery method for the revenues after the two-year period. As required by
the FERC, we filed compliance tariff changes in January 2004 to eliminate the
T&O charges within the RTO Footprint. The SECA rate issues that remain
unresolved have been set before an ALJ for settlement procedures, and the
effective date of the T&O rate elimination and SECA rates were delayed until May
1, 2004. The November orders have been appealed by a number of parties. The AEP
East companies received approximately $150 million of T&O rate revenues from
transactions delivering energy to customers in the RTO Footprint for the twelve
months ended June 30, 2003. At this time, management is unable to predict
whether the new SECA rates will fully compensate the AEP East companies for
their lost T&O rate revenues and, consequently, their impact on our future
results of operations, cash flows and financial condition.
Indiana Fuel Order
- ------------------
On July 17, 2003, I&M filed a fuel adjustment clause application requesting
authorization to implement the fixed fuel adjustment charge (fixed pursuant to a
prior settlement of the Cook Nuclear Plant Outage) for electric service for the
billing months of October 2003 through February 2004, and for approval of a new
fuel cost adjustment credit for electric service to be applicable during the
March 2004 billing month.
On August 27, 2003, the IURC issued an order approving the requested fixed fuel
adjustment charge for October 2003 through February 2004. The order further
stated that certain parties must negotiate the appropriate action on fuel to
commence on March 1, 2004. Such negotiations are ongoing. The IURC deferred
ruling on the March 2004 factor until after January 1, 2004.
Michigan 2004 Fuel Recovery Plan
- --------------------------------
The MPSC's December 16, 1999 order approved a Settlement Agreement regarding the
extended outage of the Cook Plant and fixed I&M Power Supply Cost Recovery
(PSCR) factors for the St. Joseph and Three Rivers rate areas through December
2003. In accordance with the settlement, PSCR Plan cases were not required to be
filed through the 2003 plan year. As required, I&M filed its 2004 PSCR Plan with
the MPSC on September 30, 2003 seeking new fuel and power supply recovery
factors to be effective in 2004. The case has been scheduled for hearing. As
allowed by Michigan law, the proposed factors were effective on January 1, 2004,
subject to review and possible adjustment based on the results of the hearing.
5. EFFECTS OF REGULATION
- -------------------------
Regulatory Assets and Liabilities
- ---------------------------------
Regulatory assets and liabilities are comprised of the following items:
December 31, Future
------------------------------ Recovery/
2003 2002 Refund Period
---- ---- --------------
(in millions)
Regulatory Assets:
Income Tax-related Regulatory Assets, Net $ 728 $ 639 Various Periods (a)
Transition Regulatory Assets 529 743 Up to 5 Years (a)
Regulatory Assets Designated for Securitization 1,253 331 (b)
Texas Wholesale Capacity Auction True-Up 480 262 (c)
Unamortized Loss on Reacquired Debt 116 83 Up to 40 Years (d)
Cook Nuclear Plant Restart Costs - 40 N/A
Cook Nuclear Plant Refueling Outage Levelization 57 30 (e)
Deferred Fuel Costs 24 121 1 Year (a)
CSW Merger Costs 23 32 Up to 5 Years (a)
Deferred Fuel Costs (TNC) 27 27 (c)
DOE Decontamination and Decommissioning Assessment 21 26 Up to 5 Years (a)
Other 290 354 Various Periods (f)
------- -------
Total Regulatory Assets $3,548 $2,688
======= =======
Regulatory Liabilities:
Asset Removal Costs $1,233 $ - (h)
Deferred Investment Tax Credits 422 455 Up to 26 Years (a)
Excess ARO for Nuclear Decommissioning Liability 216 - (g)
Deferred Over-Recovered Fuel Costs (TCC) 69 69 (c)
Deferred Over-Recovered Fuel Costs 63 21 (a)
Texas Retail Clawback 57 66 (c)
Other 199 328 Various Periods (f)
------- -------
Total Regulatory Liabilities $2,259 $ 939
======= =======
(a) Amount does not earn a return.
(b) Will be included in TCC's PUCT 2004 true-up proceeding and is designated
for possible securitization during 2005.
(c) Amount will be included in TCC's and TNC's 2004 true-up proceedings for
future recovery/payment over a time period to be determined in a future
PUCT proceeding.
(d) Amount effectively earns a return.
(e) Amortized over the period beginning with the commencement of an outage
and ending with the beginning of the next outage and does not earn a
return.
(f) These regulatory assets and liabilities include items both earning and
not earning a return.
(g) Amounts are accrued monthly and will be paid when the nuclear plant is
decommissioned. This also earns a return.
(h) The liability for removal costs will be discharged as removal costs are
incurred over the life of the plant.
Texas Restructuring Related Regulatory Assets and Liabilities
- -------------------------------------------------------------
Regulatory Assets Designated for Securitization, Texas Wholesale Capacity
Auction True-up regulatory assets, Deferred Over-Recovered Fuel Costs and Texas
Retail Clawback regulatory liabilities are not being currently recovered from or
returned to ratepayers. Management believes that the laws and regulations,
established in Texas for industry restructuring, provide for the recovery from
ratepayers of these net amounts. See Note 6 for a complete discussion of our
plans to recover these regulatory assets, net of regulatory liabilities.
Nuclear Plant Restart
- ---------------------
I&M completed the restart of both units of the Cook Plant in 2000. Settlement
agreements in the Indiana and Michigan retail jurisdictions that addressed
recovery of Cook Plant related outage restart costs were approved in 1999 by the
IURC and MPSC.
The amount of deferrals amortized to other O&M expenses were $40 million in
2003, 2002 and 2001. Also pursuant to the settlement agreements, accrued
fuel-related revenues of approximately $37 million in 2003 and $38 million in
2002 and 2001 were amortized as a reduction of revenues.
The amortization of O&M costs and fuel-related revenues deferred under Indiana
and Michigan retail jurisdictional settlement agreements adversely affected
results of operations through December 31, 2003 when the amortization period
ended.
Merger with CSW
- ---------------
On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. The following table summarizes significant merger-related
agreements:
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.No base rate increase before
June 15, 2003
Louisiana - SWEPCo Rate reductions to share merger
savings estimated to be $18 million
over 8 years. Base rate cap until
June 2005.
If actual merger savings are significantly less than the merger savings rate
reductions required by the merger settlement agreements in the eight-year period
following consummation of the merger, future results of operations, cash flows
and possibly financial condition could be adversely affected.
See Note 7, "Commitments and Contingencies" for information on a court decision
concerning the merger.
6. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
- ----------------------------------------------
Prior to 2003, retail customer choice began in four of the eleven state retail
jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic
electric utility companies operate. The following paragraphs discuss significant
events related to customer choice and industry restructuring.
OHIO RESTRUCTURING
- ------------------
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 the 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
. requiring the pricing of standard offer electric generation effective
January 1, 2006 at the market price used by CSPCo and OPCo 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 FERC, state legislative and regulatory developments, 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, CSPCo and OPCo filed an application with the
PUCO for approval of the transfer of functional control over certain of their
transmission facilities to PJM. In February 2003, the PUCO consolidated the June
2002 complaint with our December application. CSPCo's and OPCo's motion to
dismiss the complaint has been denied by the PUCO and the PUCO affirmed that
ruling in rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC and
elsewhere." Management is currently unable to predict the timing of the AEP East
companies' (including CSPCo and OPCo) participation in PJM, the outcome of these
proceedings before the PUCO or their impact on results of operations and cash
flows.
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. In January 2004, the
PUCO staff issued a report recommending that the PUCO seek more authority from
the Ohio Legislature on this issue. The PUCO has taken no further action in this
proceeding. Management is unable to predict the outcome of the PUCO's
investigation or its impact on results of operations, cash flows and business
practices, if any.
On March 20, 2003, the PUCO commenced a statutorily required investigation
concerning the desirability, feasibility and timing of declaring retail
ancillary, metering or billing and collection service, supplied to customers
within the certified territories of electric utilities, a competitive retail
electric service. The PUCO sent out a list of questions and set June 6, 2003 and
July 7, 2003 as the dates for initial responses and replies, respectively. CSPCo
and OPCo filed comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this proceeding or
its impact on results of operations or cash flows.
The Ohio Act provides for a Market Development Period (MDP) during which retail
customers can choose their electric power suppliers or receive Default Service
at frozen generation rates from the incumbent utility. The MDP began on January
1, 2001 and is scheduled to terminate no later than December 31, 2005. The PUCO
may terminate the MDP for one or more customer classes before that date if it
determines either that effective competition exists in the incumbent utility's
certified territory or that there is a twenty percent switching rate of the
incumbent utility's load by customer class. Following the MDP, retail customers
will receive distribution and transmission service from the incumbent utility
whose distribution rates will be approved by the PUCO and whose transmission
rates will be approved by the FERC. Retail customers will continue to have the
right to choose their electric power suppliers or receive Default Service, which
must be offered by the incumbent utility at market rates. On December 17, 2003,
the PUCO adopted a set of rules concerning the method by which it will determine
market rates for Default Service following the MDP. The rule provides for a
Market Based Standard Service Offer which would be a variable rate based on a
transparent forward market, daily market, and/or hourly market prices. The rule
also requires a fixed-rate Competitive Bidding Process for residential and small
nonresidential customers and permits a fixed-rate Competitive Bidding Process
for large general service customers and other customer classes. Customers who do
not switch to a competitive generation provider can choose between the Market
Based Standard Service Offer or the Competitive Bidding Process. Customers who
make no choice will be served pursuant to the Competitive Bidding Process.
On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the
PUCO addressing rates following the end of the MDP, which ends December 31,
2005. If approved by the PUCO, rates would be established pursuant to the plan
for the period from January 1, 2006 through December 31, 2008 instead of the
rates discussed in the previous paragraph. The plan is intended to provide rate
stability and certainty for customers, facilitate the development of a
competitive retail market in Ohio, provide recovery of environmental and other
costs during the plan period and improve the environmental performance of AEP's
generation resources that serve Ohio customers. The plan includes annual, fixed
increases in the generation component of all customers' bills (3% annually for
CSPCo and 7% annually for OPCo), and the opportunity for additional
generation-related increases upon PUCO review and approval. For residential
customers, however, if the temporary 5% generation rate discount provided by the
Ohio Act were eliminated on June 30, 2004, the fixed increases would be 1.6% for
CSPCo and 5.7% for OPCo. The generation-related increases under the plan would
be subject to caps. The plan would maintain distribution rates through the end
of 2008 for CSPCo and OPCo at the level effective on December 31, 2005. Such
rates could be adjusted for specified reasons through a PUCO filing.
Transmission charges can be adjusted to reflect applicable charges approved by
the FERC related to open access transmission, net congestion, and ancillary
services. The plan also provides for continued recovery of transition regulatory
assets and deferral of regulatory assets in 2004 and 2005 for RTO costs and
carrying costs on required environmental expenditures. A procedural schedule has
not been established for this filing. Management cannot predict whether the plan
will be approved as submitted, modified by the PUCO, or its impacts on results
of operation and cash flows.
As provided in stipulation agreements approved by the PUCO in 2000, we are
deferring customer choice implementation costs and related carrying costs that
are in excess of $40 million. The agreements provide for the deferral of these
costs as a regulatory asset until the next distribution base rate cases. The
February 2004 filing provides for the continued deferral of customer choice
implementation costs during the rate stabilization plan period. At December 31,
2003, we have incurred $66 million and deferred $26 million of such costs.
Recovery of these regulatory assets will be subject to PUCO review in future
Ohio filings for new distribution rates. If the rate stabilization plan is
approved, it would defer recovery of these amounts until after the end of the
rate stabilization period. Management believes that the customer choice
implementation costs were prudently incurred and the deferred amounts should be
recoverable in future rates. If the PUCO determines that any of the deferred
costs are unrecoverable, it would have an adverse impact on future results of
operations and cash flows.
TEXAS RESTRUCTURING
- -------------------
Texas Legislation enacted in 1999 provided the framework and timetable to allow
retail electricity competition for all customers. On January 1, 2002, customer
choice of electricity supplier began in the ERCOT area of Texas. Customer choice
has been delayed in the SPP area of Texas until at least January 1, 2007.
The Texas Legislation, among other things:
. provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
. requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
(T&D) utility;
. provides for an earnings test for each of the years 1999 through 2001
and;
. provides for a 2004 true-up proceeding. See 2004 true-up proceeding
discussion below.
The Texas Legislation required vertically integrated utilities to legally
separate their generation and retail-related assets from their transmission and
distribution-related assets. Prior to 2002, TCC and TNC functionally separated
their operations to comply with the Texas Legislation requirements. AEP formed
new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1,
2002 (the start date of retail competition). In December 2002, AEP sold the
affiliated REPs to an unaffiliated company.
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 amount not approved for securitization will be
included in regulatory assets/stranded costs in TCC's 2004 true-up proceeding.
TEXAS 2004 TRUE-UP PROCEEDING
- -----------------------------
A 2004 true-up proceeding will determine the amount and recovery of:
. net stranded generating plant costs and generation-related regulatory
assets (stranded costs),
. a true-up of actual market prices determined through legislatively-
mandated capacity auctions to the power costs used in the PUCT's ECOM
model for 2002 and 2003 (wholesale capacity auction true-up),
. final approved deferred fuel balance,
. unrefunded accumulated excess earnings,
. excess of price-to-beat revenues over market prices subject to certain
conditions and limitations (retail clawback) and
. other restructuring true-up items
The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TNC's filing in May 2004 and TCC's filing in September
2004 or 60 days after the completion of the sale of TCC's generation assets, if
later.
Stranded Costs and Generation-Related Regulatory Assets
- -------------------------------------------------------
Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generating assets for determining stranded
costs. TCC is the only AEP subsidiary that has stranded costs under the Texas
Legislation. We have elected to use the sale of assets method to determine the
market value of all of our generation assets for stranded cost purposes. When
completed, the sale of our generation assets will substantially complete the
required separation of generation assets from transmission and distribution
assets. For purposes of the 2004 true-up proceeding, the amount of stranded
costs under this market valuation methodology will be the amount by which the
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 TCC's 2004 true-up proceeding.
In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval
of a sales process for all of its generating facilities. In March 2003, the PUCT
dismissed TCC's divestiture filing, determining that it was more appropriate to
address allowable valuation methods for the nuclear asset in a rulemaking
proceeding. The PUCT approved a rule, in May 2003, which allows the market value
obtained by selling nuclear assets to be used in determining stranded costs.
Although the PUCT declined to review TCC's proposed sale of assets process, the
PUCT has hired a consultant to advise TCC during the sale of the generation
assets. TCC's sale of its generating assets will be subject to a review in the
2004 true-up proceeding.
In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generating capacity in Texas. In order to sell these assets, we anticipate
retiring TCC's first mortgage bonds by making open market purchases or defeasing
the bonds. Bids were received for all of TCC's generating plants. In January
2004, TCC agreed to sell its 7.8% ownership interest in the Oklaunion Power
Station to an unaffiliated third party for $43 million. The sale of TCC's
remaining generation is pending. Additional regulatory approvals will be
required to complete the sale of the generation assets, including NRC approval
of the transfer of our interest in STP.
In the 2004 true-up proceeding, the amount of stranded costs under this market
valuation methodology will be the amount by which the book value of TCC's
generating assets, including regulatory assets and liabilities that were not
securitized and reduced by mitigation including unrefunded excess earnings,
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 TCC's 2004 true-up
proceeding.
After the 2004 true-up proceeding, TCC may seek to issue securitization revenue
bonds for its stranded costs and recover the costs of the securitization bonds
through transmission and distribution rates. Based upon the Oklaunion sale and
the bid information for the remaining generation, we recorded an impairment of
generating assets of $938 million in December 2003 as a regulatory asset (see
Note 10). The recovery of the regulatory asset will be subject to review and
approval by the PUCT as a stranded cost in the 2004 true-up proceeding.
Wholesale Capacity Auction True-up
- ----------------------------------
Texas Legislation also requires that electric utilities and their affiliated
power generation companies (PGC) offer for sale at auction, in 2002 and 2003 and
after, 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. Actual market power prices received in the
state mandated auctions will be used to calculate the wholesale capacity auction
true-up adjustment for TCC for the 2004 true-up proceeding.
TCC recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction true-up for
the years 2002 and 2003. In TCC's UCOS proceeding, the PUCT estimated that TCC
had negative stranded costs. In its true-up rule, the PUCT determined that the
wholesale capacity auction true-up proceeds should be offset against negative
stranded costs. However, in March 2003, the Texas Court of Appeals ruled that
under the restructuring legislation, other 2004 true-up items, including the
wholesale capacity auction true-up regulatory asset, could be recovered
regardless of the level of stranded costs.
In the fourth quarter of 2003, the PUCT approved a true-up filing package
containing calculation instructions similar to the methodology employed by TCC
to calculate the amount recorded for recovery under its wholesale capacity
auction true-up. The PUCT will review the $480 million wholesale capacity
regulatory asset for recovery as part of the 2004 true-up proceeding.
Fuel Balance Recoveries
- -----------------------
In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail sales
within its ERCOT service area for inclusion in the 2004 true-up proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case that established TNC's unrecovered fuel balance, including interest for the
ERCOT service territory, at $6.2 million. This balance will be included in TNC's
2004 true-up proceeding. TNC is waiting for a written order from the PUCT, after
which it will request a rehearing.
In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its
deferred over-recovery of fuel balance for inclusion in the 2004 true-up
proceeding. In February 2004, an ALJ issued recommendations finding a $205
million over-recovery in this fuel proceeding. Management is unable to predict
the amount of TCC's fuel over-recovery which will be included in its 2004
true-up proceeding.
See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 4 "Rate Matters"
for further discussion.
Unrefunded Excess Earnings
- --------------------------
The Texas Legislation provides for the calculation of excess earnings for each
year from 1999 through 2001. The total excess earnings determined for the three
year period were $3 million for SWEPCo, $47 million for TCC and $19 million for
TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related
deferred income taxes and appealed the PUCT's final 2000 excess earnings to the
Travis County District Court which upheld the PUCT ruling. The District Court's
ruling was appealed to the Third Court of Appeals. In August 2003, the Third
Court of Appeals reversed the PUCT order and the District Court's judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied and the
PUCT chose not to appeal the ruling any further. Appeal of the same issue from
the PUCT's 2001 order is pending before the District Court. Since an expense and
regulatory liability had been accrued in prior years in compliance with the PUCT
orders, the companies reversed a portion of their regulatory liability for the
years 2000 and 2001 consistent with the Appeals Court's decision and credited
amortization expense during the third quarter of 2003. Pre-tax amounts reversed
by company were $5 million for TCC, $3 million for TNC and $1 million for
SWEPCo.
In 2001, the PUCT issued an order requiring TCC to return estimated excess
earnings by reducing distribution rates by approximately $55 million plus
accrued interest over a five-year period beginning January 1, 2002. 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 and that it was
inappropriate for the PUCT to order a refund prior to TCC's 2004 true-up
proceeding. TCC appealed the PUCT's refund of excess earnings to the Travis
County District Court. That court affirmed the PUCT's decision and further
ordered that the refunds be provided to customers. TCC has appealed the decision
to the Court of Appeals.
Retail Clawback
- ---------------
The Texas Legislation provides for the affiliated PTB REP serving residential
and small commercial customers to refund to its T&D utility the excess of the
PTB revenues over market prices (subject to certain conditions and a limitation
of $150 per customer). This is the retail clawback. If, prior to January 1,
2004, 40% of the load for the residential or small commercial classes is served
by competitive REPs, the retail clawback is not applicable for that class of
customer. During 2003, TCC and TNC filed to notify the PUCT that competitive
REPs serve over 40% of the load in the small commercial class. The PUCT approved
TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a regulatory
liability of approximately $9 million for the small commercial retail clawback
on its REP's books. When the PUCT certified that the REP's in TCC and TNC
service territories had reached the 40% threshold, the regulatory liability was
no longer required for the small commercial class and was reversed in December
2003. At December 31, 2003, the remaining retail clawback regulatory liability
was $57 million.
When the 2004 true-up proceeding is completed, TCC intends to file to recover
PUCT-approved stranded costs and other true-up amounts that are in excess of
current securitized amounts, plus appropriate carrying charges and other true-up
amounts, through non-bypassable competition transition charge in the regulated
T&D rates. TCC may also seek to securitize certain of the approved stranded
plant costs and regulatory assets that were not previously recovered through the
non-bypassable transition charge. The annual costs of securitization are
recovered through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.
In the event we are unable, after the 2004 true-up proceeding, to recover all or
a portion of our stranded plant costs, generation-related regulatory assets,
unrecovered fuel balances, wholesale capacity auction true-up regulatory assets,
other restructuring true-up items and costs, it could have a material adverse
effect on 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,
2003, 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, 2003 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.
ARKANSAS RESTRUCTURING
- ----------------------
In February 2003, Arkansas repealed customer choice legislation originally
enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71
regulatory accounting, which had been discontinued in 1999. The reapplication of
SFAS 71 had an insignificant effect on results of operations and financial
condition. As a result of reapplying SFAS 71, derivative contract gains/losses
for transactions within AEP's traditional marketing area allocated to Arkansas
will not affect income until settled. That is, such positions will be recorded
on the balance sheet as either a regulatory asset or liability until realized.
WEST VIRGINIA RESTRUCTURING
- ---------------------------
APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first
quarter of 2003 after new developments during the quarter prompted an analysis
of the probability of restructuring becoming effective.
In 2000, the WVPSC issued an order approving an electricity restructuring plan,
which the WV Legislature approved by joint resolution. The joint resolution
provided that the WVPSC could not implement the plan until the WV legislature
made tax law changes necessary to preserve the revenues of state and local
governments.
In the 2001 and 2002 legislative sessions, the WV Legislature failed to enact
the required legislation that would allow the WVPSC to implement the
restructuring plan. Due to this lack of legislative activity, the WVPSC closed
two proceedings related to electricity restructuring during the summer of 2002.
In the 2003 legislative session, the WV Legislature failed to enact the required
tax legislation. Also, legislation enacted in March 2003 clarified the
jurisdiction of the WVPSC over electric generation facilities in WV. In March
2003, APCo's outside counsel advised us that restructuring in WV was no longer
probable and confirmed facts relating to the WVPSC's jurisdiction and rate
authority over APCo's WV generation. APCo has concluded that deregulation of the
WV generation business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.
Reapplying SFAS 71 in WV had an insignificant effect on results of operations
and financial condition. As a result, derivative contract gains/losses related
to transactions within AEP's traditional marketing area allocated to WV will not
affect income until settled. That is, such positions will be recorded on the
balance sheet as either a regulatory asset or liability until realized.
Positions outside AEP's traditional marketing area will continue to be
marked-to-market.
7. COMMITMENTS AND CONTINGENCIES
- ---------------------------------
ENVIRONMENTAL
- -------------
Federal EPA Complaint and Notice of Violation
- ---------------------------------------------
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints
against our subsidiaries in U.S. District Court for the Southern District of
Ohio. The court also consolidated a separate lawsuit, initiated by certain
special interest groups, with the Federal EPA case. The alleged modifications
relate to costs that were incurred at our generating units 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.
On August 7, 2003, the District Court issued a decision following a liability
trial in a case pending in the Southern District of Ohio against Ohio Edison
Company, an unaffiliated utility. The District Court held that replacements of
major boiler and turbine components that are infrequently performed at a single
unit, that are performed with the assistance of outside contractors, that are
accounted for as capital expenditures, and that require the unit to be taken out
of service for a number of months are not "routine" maintenance, repair, and
replacement. The District Court also held that a comparison of past actual
emissions to projected future emissions must be performed prior to any
non-routine physical change in order to evaluate whether an emissions increase
will occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all of the
challenged activities in that case were not routine, and that the changes
resulted in significant net increases in emissions for certain pollutants. A
remedy trial is scheduled for July 2004.
Management believes that the Ohio Edison decision fails to properly evaluate and
apply the applicable legal standards. The facts in our case also vary widely
from plant to plant. Further, the Ohio Edison decision is limited to liability
issues, and provides no insight as to the remedies that might ultimately be
ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South Carolina
issued a decision on cross-motions for summary judgment prior to a liability
trial in a case pending against Duke Energy Corporation, an unaffiliated
utility. The District Court denied all the pending motions, but set forth the
legal standards that will be applied at the trial in that case. The District
Court determined that the Federal EPA bears the burden of proof on the issue of
whether a practice is "routine maintenance, repair, or replacement" and on
whether or not a "significant net emissions increase" results from a physical
change or change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the relevant
source category" in determining if it is "routine." Further, the Federal EPA
must calculate emissions by determining first whether a change in the maximum
achievable hourly emission rate occurred as a result of the change, and then
must calculate any change in annual emissions holding hours of operation
constant before and after the change. The Federal EPA has requested
reconsideration of this decision, or in the alternative, certification of an
interlocutory appeal to the Fourth Circuit Court of Appeals.
On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by the Federal
EPA to the Tennessee Valley Authority for alleged Clean Air Act violations. The
11th Circuit determined that the administrative compliance order was not a final
agency action, and that the enforcement provisions authorizing the issuance and
enforcement of such orders under the Clean Air Act are unconstitutional.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG),
of which our subsidiaries are members, to reopen petitions for review of the
1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA
claims in our case and other related cases. On August 4, 2003, UARG filed a
motion to separate and expedite review of their challenges to the 1980 and 1992
rulemakings from other unrelated claims in the consolidated appeal. The Circuit
Court denied that motion on September 30, 2003. The central issue in these
petitions concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement actions. A
decision by the D. C. Circuit Court could significantly impact further
proceedings in our case.
On August 27, 2003, the Administrator of the Federal EPA signed a final rule
that defines "routine maintenance repair and replacement" to include
"functionally equivalent equipment replacement." Under the new final rule,
replacement of a component within an integrated industrial operation (defined as
a "process unit") with a new component that is identical or functionally
equivalent will be deemed to be a "routine replacement" if the replacement does
not change any of the fundamental design parameters of the process unit, does
not result in emissions in excess of any authorized limit, and does not cost
more than twenty percent of the replacement cost of the process unit. The new
rule is intended to have prospective effect, and will become effective in
certain states 60 days after October 27, 2003, the date of its publication in
the Federal Register, and in other states upon completion of state processes to
incorporate the new rule into state law. On October 27, 2003 twelve states, the
District of Columbia and several cities filed an action in the United States
Court of Appeals for the District of Columbia Circuit seeking judicial review of
the new rule. The UARG has intervened in this case. On December 24, 2003, the
Circuit Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.
We are unable to estimate the loss or range of loss related to the contingent
liability for civil penalties under the CAA proceedings. We are also 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 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 future results of operations and cash flows.
NUCLEAR
- -------
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 $10.6 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $300
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 $101 million on each licensed reactor in the U.S. payable in
annual installments of $10 million. As a result, I&M could be assessed $202
million per nuclear incident payable in annual installments of $20 million. TCC
could be assessed $50 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 million and $2 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 $43 million for I&M and $2 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 in 2004 with
increases in required third party financial protection for nuclear incidents.
SNF 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 $226 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, 2003, 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. In November 2003, I&M filed to extend the operating licenses of the
two Cook Plant units for up to an additional 20 years. The review of the license
extension application is expected to take at least two years. 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 $821 million to $1,080 million in 2003 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 2003, 2002 and 2001.
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 2003, 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 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.
TCC's nuclear decommissioning trust asset and liability are included in held for
sale amounts on the Consolidated Balance Sheets.
OPERATIONAL
- -----------
Construction and Commitments
- ----------------------------
The AEP System has substantial construction commitments to support its
operations. Aggregate construction expenditures for 2004-2006 for consolidated
domestic and foreign operations are estimated to be $5.8 billion including
amounts for proposed environmental rules.
Our subsidiaries have entered into long-term contracts to acquire fuel for
electric generation. The longest contract extends to the year 2014. The
contracts provide for periodic price adjustments and contain various clauses
that would release the subsidiaries from their obligations under certain
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.
Potential Uninsured Losses
- --------------------------
Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including, but not limited to, liabilities relating to damage to
the Cook Plant or STP and costs of replacement power in the event of a nuclear
incident at the Cook Plant or STP. Future losses or liabilities which are not
completely insured, unless recovered from customers, could have a material
adverse effect on results of operations, cash flows and financial condition.
Power Generation Facility
- -------------------------
We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. Juniper will own the Facility and lease it to AEP after construction is
completed and we will sublease the Facility to The Dow Chemical Company (Dow).
Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW
of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years
under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming.
On September 5, 2003, TEM and AEP separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. We
allege that TEM has breached the PPA, and we are seeking a determination of our
rights under the PPA. TEM alleges that the PPA never became enforceable or
alternatively, that the PPA has already been terminated as the result of AEP
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, we could be adversely affected to the extent we are unable to find other
purchasers of the power with similar contractual terms to the extent we do not
fully recover claimed termination value damages from TEM. The corporate parent
of TEM has provided a limited guaranty.
On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM
basically argued that in the absence of mutually agreed upon protocols there was
no commercially reasonable means to obtain or deliver the electric power
products and therefore the PPA is not enforceable. TEM further argued that the
creation of the protocols is not subject to arbitration. The arbitrator ruled in
favor of TEM on February 11, 2004 and concluded that the "creation of protocols"
was not subject to arbitration, but did not rule upon the merits of TEM's claim
that the PPA is not enforceable.
If commercial operation is not achieved for purposes of the PPA by April 30,
2004, TEM may claim that it can terminate the PPA and is owed liquidating
damages of approximately $17.5 million. TEM may also claim that we are not
entitled to receive any termination value for the PPA.
See further discussion in Notes 10 and 16.
Merger Litigation
- -----------------
In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the
SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the
requirements of the PUHCA and sent the case back to the SEC for further review.
Specifically, the court told the SEC to revisit its conclusion that the merger
met PUHCA requirements that utilities be "physically interconnected" and
confined to a "single area or region."
In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUCHA's single
region requirement because it is now technically possible to centrally control
the output of power plants across many states. In its ruling, the appeals court
said that the SEC failed to 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, certain subsidiaries of 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 from Enron 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
facility and the appurtenant pipelines. We have engaged in discussions with
Enron concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between AEP and
Enron relating to our acquisition of HPL and the possible resolution of
outstanding energy trading issues. We have considered the possible outcomes of
these issues in our impairment analysis of HPL; however, actual results could
differ from those estimates. We are unable to predict whether these discussions
will lead to an agreement on these subjects. In January 2004, AEP and its
subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the
U.S. Bankruptcy Court claiming that Enron does not have the right to reject the
Bammel storage facility agreement or the cushion gas use agreement, described
below. In February 2004 Enron filed Notices of Rejection regarding the cushion
gas use agreement and other incidental agreements. We have objected to Enron's
attempted rejection of these agreements. Management is unable to predict the
outcome of these proceedings or the impact on results of operations, cash flows
or financial condition.
We also entered into an agreement with BAM Lease Company which grants HPL the
exclusive right to use approximately 65 billion cubic feet of cushion gas
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust (owned by Enron and Bank of America (BOA)) purports to have a lien on
55 billion cubic feet of this cushion gas. These banks claim to have certain
rights to the cushion gas in certain events of default. In connection with our
acquisition of HPL, the banks and Enron entered into an agreement granting HPL's
exclusive use of 65 billion cubic feet of cushion gas. Enron and the banks
released HPL from all prior and future liabilities and obligations in connection
with the financing arrangement. After the Enron bankruptcy, HPL was informed by
the banks of a purported default by Enron under the terms of the financing
arrangement. In July 2002, the banks filed a lawsuit against HPL in the state
court of Texas seeking a declaratory judgment that they have a valid and
enforceable security interest in gas purportedly in the Bammel storage facility
which would permit them to cause the withdrawal of up to 55 billion cubic feet
of gas from the storage facility. In September 2002, HPL filed a general denial
and certain counterclaims against the banks including that Enron was a necessary
and indispensable party to the Texas state court proceeding initiated by BOA.
HPL also filed a motion to dismiss, which was denied. In December 2003, the
Texas state court granted partial summary judgment in favor of the banks. HPL
appealed this decision. We have considered the possible outcomes of these issues
in our impairment analysis of HPL; however, actual results could differ from
those estimates. Management is unable to predict the outcome of this lawsuit or
its impact on results of operations, cash flows and financial condition.
In October 2003, AEP Energy Services Gas Holding Company filed a lawsuit against
BOA in the United States District Court for the Southern District of Texas. On
January 8, 2004, this lawsuit was amended and seeks damages for BOA's breach of
contract, negligent misrepresentation and fraud in connection with transactions
surrounding our acquisition of HPL from Enron including entering into the Bammel
storage facility lease arrangement with Enron and the cushion gas arrangements
with BOA and Enron. BOA led a lending syndicate involving the 1997 gas
monetization that Enron and its subsidiaries undertook and the leasing of the
Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA
made misrepresentations and engaged in fraud to induce and promote the stock
sale of HPL, that BOA directly benefited from the sale of HPL and that AEP
undertook the stock purchase and entered into the Bammel storage facility lease
arrangement with Enron and the cushion gas arrangement with Enron and BOA based
on misrepresentations that BOA made about Enron's financial condition that BOA
knew or should have known were false including that the 1997 gas monetization
did not contravene or constitute a default of any federal, state, or local
statute, rule, regulation, code or any law.
In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related collateral
across various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas related trading transactions. We will
assert our right to offset trading payables owed to various Enron entities
against trading receivables due to several AEP subsidiaries. Management is
unable to predict the outcome of this lawsuit or its impact on our results of
operations, cash flows or financial condition.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. Management is unable to predict the
outcome of this lawsuit or its impact on our results of operations, cash flows
or financial condition.
During 2002 and 2001, we expensed a total of $53 million ($34 million net of
tax) for our estimated loss from the Enron bankruptcy. The amount expensed was
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. As noted above, Enron has
challenged our offsetting of receivables and payables and the Bammel storage
facility lease agreement and cushion gas agreement. Management is unable to
predict the final resolution of these disputes, however the impact on results of
operations, cash flows and financial condition could be material.
Shareholder Lawsuits
- --------------------
In the fourth quarter of 2002 and the first quarter of 2003, 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 we failed to disclose that
alleged "round trip" trades resulted in an overstatement of revenues, that we
failed to disclose that our traders falsely reported energy prices to trade
publications that published gas price indices and that we failed to disclose
that we 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
Court has appointed a lead plaintiff who has filed a Consolidated Amended
Complaint. We have filed a Motion to Dismiss the Consolidated Amended Complaint.
The Motion has been briefed by the parties. Also, in the first quarter of 2003,
a lawsuit making essentially the same allegations and demands was filed in state
Common Pleas Court, Columbus, Ohio against AEP, certain executives, members of
the Board of Directors and our independent auditor. We removed this case to
federal District Court in Columbus and the Court has denied plaintiff's motion
to remand the case to state court. We have moved to consolidate this case with
the other pending cases. We intend to continue to vigorously defend against
these actions.
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 our gas trading operations. These cases have been stayed pending
the outcome of our Motion to Dismiss the Consolidated Amended Complaint in the
federal securities lawsuits. If these cases do proceed, we intend to vigorously
defend against them. Also, in the fourth quarter of 2002 and the first quarter
of 2003, three putative class action lawsuits were filed against AEP, certain
executives and AEP's Employee Retirement Income Security Act (ERISA) Plan
Administrator alleging violations of ERISA in the selection of AEP stock as an
investment alternative and in the allocation of assets to AEP stock. The ERISA
actions are pending in federal District Court, Columbus, Ohio. In these actions,
the plaintiffs seek recovery of an unstated amount of compensatory damages,
attorney fees and costs. We have filed a Motion to Dismiss these actions. The
parties have fully briefed this Motion. We intend to continue to vigorously
defend against these claims.
California Lawsuits
- -------------------
In November 2002, the 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 and all defendants have
filed motions to dismiss. AEP has been dismissed from the case. The plaintiff
had stated an intention to amend the complaint to add an AEP subsidiary as a
defendant. The plaintiff amended the complaint but did not name any AEP company
as a defendant. In November 2003, Texas-Ohio Energy, Inc. filed a lawsuit in the
United States District Court for the Eastern District of California alleging
that AEP and a large number of other energy companies conspired to manipulate
natural gas prices in California in violation of federal and state antitrust and
unfair competition laws. Certain of the other defendants in this case have filed
a Notice of Potential Tag-Along Action with the Judicial Panel on Multi-District
Litigation seeking to have this case transferred to the United States District
Court for the District of Nevada where there are a number of other cases now
pending that assert claims regarding the alleged manipulation of energy markets
in California. None of the AEP companies is a party to these other pending
cases. Once venue for the Texas-Ohio Energy, Inc. case is determined, we plan to
move to dismiss the complaint and otherwise vigorously defend against these
claims. In February 2004, two individuals on behalf of themselves and two
businesses they own and another individual filed an action in state court in San
Diego County, California against a large number of energy companies including
AEPES. This action alleges violations of state antitrust and unfair competition
laws based on alleged manipulation of gas price indices. This case is in the
initial pleading states. We plan to vigorously defend against these claims.
Cornerstone Lawsuit
- -------------------
In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Thereafter, two similar actions were filed in the same court against a number of
companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. On December
5, 2003, the Court issued its initial Pretrial Order consolidating all related
cases, appointing co-lead counsel and providing for the filing of an amended
consolidated complaint. In January 2004, plaintiffs filed an amended
consolidated complaint. We plan to move to dismiss the complaint and otherwise
vigorously defend against these claims.
Texas Commercial Energy, LLP Lawsuit
- ------------------------------------
Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal
District Court in Corpus Christi, Texas, in July 2003, against us and four AEP
subsidiaries, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made against
the AEP companies, range from anticompetitive bidding to withholding power. TCE
alleges that these activities resulted in price spikes requiring TCE to post
additional collateral and ultimately forced it into bankruptcy when it was
unable to raise prices to its customers due to fixed price contracts. The suit
alleges over $500 million in damages for all defendants and seeks recovery of
damages, exemplary damages and court costs. Two additional parties, Utility
Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as
plaintiffs asserting similar claims. We filed a Motion to Dismiss in September
2003. In February 2004, TCE filed an amended complaint. We intend to file a
motion to dismiss the amended complaint and otherwise vigorously defend against
the claims.
Bank of Montreal Claim
- ----------------------
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had
acted contrary to the appropriate trading contract and industry practice in
terminating the contract and calculating termination and liquidation amounts and
that BOM had acknowledged just prior to the termination and liquidation that it
owed us approximately $68 million. We are claiming that BOM owes us at least $45
million. 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.
Arbitration of Williams Claim
- -----------------------------
In October 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding resulted 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 we owed approximately $130
million in connection with the termination and liquidation of all trading deals.
Williams and AEP settled the dispute and we paid $90 million to Williams in June
2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter did not have a
material impact on results of operations or financial condition.
Arbitration of PG&E Energy Trading, LLC Claim
- ---------------------------------------------
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement and we paid approximately $11
million to PGET. The settlement amount approximated the amount payable that, in
the ordinary course of business, we recorded as part of our trading activity
using MTM accounting. As a result, the settlement payment did not have a
material impact on results of operations, cash flows or financial condition.
Energy Market Investigation
- ---------------------------
AEP and other energy market participants received data requests, subpoenas and
requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity
Futures Trading Commission (CFTC), the U.S. Department of Justice and the
California attorney general during 2002. Management responded to the inquiries
and provided the requested information and has continued to respond to
supplemental data requests in 2003 and 2004.
In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC asking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. The case is in the initial pleading stage with our
response to the complaint currently due on May 18, 2004. Although management is
unable to predict the outcome of this case, it is not expected to have a
material effect on results of operations due to a provision recorded in December
2003.
In January 2004, the CFTC issued a request for documents and other information
in connection with a CFTC investigation of activities affecting the price of
natural gas in the fall of 2003. We are responding to that request.
Management cannot predict what, if any further action, any of these governmental
agencies may take with respect to these matters.
FERC Proposed Standard Market Design
- ------------------------------------
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, which sought to standardize the structure and operation of
wholesale electricity markets across the country. Key elements of FERC's
proposal included 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 issued a "white paper" on the proposal in April 2003, in
response to the numerous comments that the FERC received on its proposal.
Management does not know if or when the FERC will finalize a rule for SMD. Until
any potential rule is finalized, management cannot predict its effect on cash
flows and results of operations.
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. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Management is unable to predict the timing of any
further action by the FERC or its affect of future results of operations and
cash flows.
8. GUARANTEES
- --------------
There are no liabilities recorded for guarantees entered into prior to December
31, 2002 in accordance with FIN 45. There are certain immaterial liabilities
recorded for guarantees entered into subsequent to December 31, 2002. There is
no collateral held in relation to any guarantees and there is no recourse to
third parties in the event any guarantees are drawn unless specified below.
LETTERS OF CREDIT
- -----------------
We have entered into standby letters of credit (LOC) with third parties. These
LOCs cover gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. All of these LOCs were issued by us in the
ordinary course of business. At December 31, 2003, the maximum future payments
for all the LOCs are approximately $227 million with maturities ranging from
January 2004 to January 2011. Included in these amounts is TCC's LOC of
approximately $43 million with a maturity date of November 3, 2005. As the
parent of all these subsidiaries, we hold all assets of the subsidiaries as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.
We have guaranteed 50% of the principal and interest payments as well as 100% of
a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which we are a 50%
owner. In the event Fort Lupton does not make the required debt payments, we
have a maximum future payment exposure of approximately $7 million, which
expires May 2008.
In the event Fort Lupton is unable to perform under its PPA agreement, we have a
maximum future payment exposure of approximately $15 million, which expires June
2019.
We have guaranteed 50% of a security deposit for gas transmission as well as 50%
of a Power Purchase Agreement (PPA) of Orange Cogeneration (Orange), an IPP of
which we are a 50% owner. In the event Orange fails to make payments in
accordance with agreements for gas transmission, we have a maximum future
payment exposure of approximately $1 million, which expires June 2023. In the
event Orange is unable to perform under its PPA agreement, we have a maximum
future payment exposure of approximately $1 million, which expires June 2016.
GUARANTEES OF THIRD-PARTY OBLIGATIONS
- -------------------------------------
CSW Energy and CSW International
- --------------------------------
CSW Energy and CSW International have guaranteed 50% of the required debt
service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a
50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve
as a part of a 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 $4 million, which expires June 2020.
AEP Utilities
- -------------
AEP Utilities guaranteed 50% of the required debt service reserve for Polk Power
Partners, an IPP of which CSW Energy owns 50%. In the event that Polk Power does
not make the required debt payments, AEP Utilities has a maximum future payment
exposure of approximately $5 million, which expires July 2010.
SWEPCo
- ------
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 capital lease obligations and term loan payments of the mining
contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under
any of these agreements,
SWEPCo's total future maximum payment exposure is approximately $58 million with
maturity dates ranging from June 2005 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, 2003, the cost to reclaim the mine in 2035 is
estimated to be approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46
(see Note 2). Upon consolidation, SWEPCo recorded the assets and liabilities of
Sabine ($78 million). Also, after consolidation, SWEPCo currently records all
expenses (depreciation, interest and other operation expense) of Sabine and
eliminates Sabine's revenues against SWEPCo's fuel expenses. There is no
cumulative effect of an accounting change recorded as a result of the
requirement to consolidate, and there is no change in net income due to the
consolidation of Sabine.
INDEMNIFICATIONS AND OTHER GUARANTEES
- -------------------------------------
We entered 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. With respect to sale
agreements, our exposure generally does not exceed the sale price. We cannot
estimate the maximum potential exposure for any of these indemnifications
entered into prior to December 31, 2002 due to the uncertainty of future events.
In 2003 we entered into several sale agreements discussed in Note 10. These sale
agreements include indemnifications with a maximum exposure of approximately $57
million. There are no material liabilities recorded for any indemnifications
entered into during 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.
We 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, 2003, the maximum potential loss for these
lease agreements was approximately $28 million assuming the fair market value of
the equipment is zero at the end of the lease term.
See Note 16 "Leases" for disclosure of lease residual value guarantees.
9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
- ---------------------------------------------
In response to difficult conditions in our 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, we paid $9.5 million to these terminated employees in the fourth quarter
of 2002. No additional termination benefits expense related to the SEI
initiative was recorded in 2003, and the remaining SEI related payments were
made in 2003. The termination benefits expense is classified as Maintenance and
Other Operation expense on our Consolidated Statements of Operations. We
determined that the termination of the employees under our SEI initiative did
not constitute a plan curtailment of any of our retirement benefit plans.
10. ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS, IMPAIRMENTS, ASSETS
HELD FOR SALE AND ASSETS HELD AND USED
- -----------------------------------------------------------------------------
ACQUISITIONS
- ------------
2002
- ----
Acquisition of Nordic Trading (Investments - UK Operations segment)
- -------------------------------------------------------------------
In January 2002 we acquired the trading operations, including key staff, of
Enron's Norway and Sweden-based energy trading businesses (Nordic Trading).
Results of operations are included in our Consolidated Statements of Operations
from the date of acquisition. Subsequently in the fourth quarter of 2002, a
decision was made to exit this non-core European trading business. The sale of
Nordic Trading in the second quarter of 2003 is discussed in the "Dispositions"
section of this note.
Acquisition of USTI (Investments - Other segment)
- -------------------------------------------------
In January 2002, we 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 our affiliates and
external customers. Results of operations are included in our Consolidated
Statements of Operations from the date of acquisition.
2001
- ----
Houston Pipe Line Company (Investments - Gas Operations segment)
- ----------------------------------------------------------------
On June 1, 2001, through a wholly-owned subsidiary, we 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 prepaid lease of a gas storage
facility and certain gas marketing contracts. The purchase method of accounting
was used to record the acquisition. During 2003 we recorded impairment and other
losses for HPL and related gas operations of $315 million ($228 million net of
tax).
U.K. Generation Plants (Investments - UK Operations segment)
- -------------------------------------------------------------
In December 2001, we acquired 4,000 megawatts of coal-fired generation from
Fiddler's Ferry, a four-unit, 2,000 MW station on the River Mersey in northwest
England, and Ferrybridge, a four-unit, 2,000 MW station on the River Aire in
northeast England and related coal stocks. These assets were acquired for a cash
payment of $942.3 million and the assumption of certain liabilities. During 2003
these assets became held-for-sale and we reported the operations as
discontinued. See U.K. Generation Plants in the "Discontinued Operations"
section of this note for further information.
Other Acquisitions (Various segments)
- -------------------------------------
We also purchased the following assets or acquired the following businesses from
July 2001 through December 2001:
. Dolet Hills mining operations were purchased by SWEPCo, an AEP
subsidiary, and SWEPCo also assumed the existing mine reclamation
liabilities at its jointly owned lignite reserves in Louisiana.
. Quaker Coal Company as part of a bankruptcy proceeding settlement was
acquired, including certain liabilities. The acquisition includes
property, coal reserves, mining operations and royalty interests in
Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. We continue to
operate the mines and facilities. See AEP Coal in the "Assets Held for
Sale" section of this note for further information on our decision to
dispose of this investment.
. MEMCO Barge Line was acquired adding 1,200 hopper barges and 30 towboats
to AEP's existing barging fleet. MEMCO added major barging operations on
the Mississippi and Ohio rivers to AEP's barging operations on the Ohio
and Kanawha rivers.
. A 20% equity interest in Caiua, a Brazilian electric operating company
which is a subsidiary of Vale was acquired by converting a total of $66
million on an existing loan and accrued interest on that loan into Caiua
equity. See Grupo Rede Investment in the "Dispositions" section of this
note for further information.
. Indian Mesa Wind Project (referred to as "Desert Sky") consisting of 160
MW of wind generation located near Fort Stockton, Texasm was purchased.
. Enron's London-based international coal trading group was acquired by
purchasing existing contracts and hiring key staff.
Management recorded the assets acquired and liabilities assumed at their
estimated fair values based on currently available information and on current
assumptions as to future operations.
DISPOSITIONS
- ------------
2003
- ----
C3 Communications (Investments - Other segment)
- -----------------------------------------------
In February 2003, C3 Communications sold the majority of its assets for a sales
price of $7.25 million. We provided for an $82 million pre-tax ($53 million
after-tax) asset impairment in December 2002 and the effect of the sale on 2003
results of operations was not significant. The impairment is classified in Asset
Impairments and Other Related Changes in our Consolidated Statements of
Operations. See "Assets Held for Sale" section of this note for information on
assets and liabilities held for sale at December 31, 2002 related to our
"telecommunications" businesses.
Mutual Energy Companies (Utility Operations segment)
- ----------------------------------------------------
On December 23, 2002 we sold 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. The buyer 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. We recorded a net gain
totaling $83.7 million after-tax ($129 million pre-tax) in Other Income during
2002. We provided the buyer with a power supply contract for the two REPs and
back-office services related to these customers for a two-year period. In
addition, we 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. No revenue was recorded in 2003 related to
these sharing agreements. Under the Texas Legislation, REPs are subject to a
clawback liability if customer change does not attain thresholds required by the
legislation. We are responsible for a portion of such liability, if any, for the
period we operated the REPs in the Texas competitive retail market (January 1,
2002 through December 23, 2002). In addition, we retained responsibility for
regulatory obligations arising out of operations before closing. Our
wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an
up-front payment of approximately $30 million from the buyer 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
as of December 31, 2002 and are being amortized over the two-year term of the
back office service agreement.
In February 2003, we completed the sale of MESC for $30.4 million dollars and
realized a pre-tax gain of approximately $39 million, which included the
recognition of the remaining balance of the original $30 million prepayment ($27
million), as no further service obligations existed for MESC.
Water Heater Assets (Utility Operations segment)
- ------------------------------------------------
We sold our water heater rental program for $38 million and recorded a pre-tax
loss of $3.9 million in the first quarter of 2003 based upon final terms of the
sale agreement. We had provided for a $7.1 million pre-tax charge in the fourth
quarter 2002 based on an estimated sales price ($3.2 million asset impairment
charge and $3.9 million lease prepayment penalty). The impairment loss is
included in Investment Value Losses in our Consolidated Statements of
Operations. We 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 offer the assets for sale. See the "Assets
Held for Sale" section of this Note for assets and liabilities held for sale as
of December 31, 2002.
AEP Gas Power Systems (Investments - Other segment)
- ---------------------------------------------------
In 2001, we acquired a 75% interest in a startup company, seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. In
January 2003, AEP Gas Power Systems, LLC sold its assets. We recognized a
goodwill impairment loss of $12.3 million pre-tax in the first quarter of 2002
due to technological and operational problems (also see Note 3). The impairment
loss was recorded in Investment Value Losses on our Consolidated Statements of
Operations. The fair values of the remaining assets and liabilities as of
December 31, 2002 were excluded from held for sale on our Consolidated Balance
Sheets as the impact was not significant. The effect of the asset sale on the
first quarter 2003 results of operations was not significant.
Newgulf Facility (Investments - Other segment)
- ----------------------------------------------
In 1995, we purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002, we began negotiations
with a likely buyer of the facility. We estimated a pre-tax loss on sale of
$11.8 million based on the indicative bid. This loss was recorded as Asset
Impairments and Other Related Charges on our Consolidated Statements of
Operations during the fourth quarter 2002. Newgulf's Property, Plant and
Equipment, net of accumulated depreciation, was classified on our Consolidated
Balance Sheets as held for sale at December 31, 2002. During the second quarter
of 2003 we completed the sale of Newgulf and the impact on earnings in 2003 was
not significant.
Nordic Trading (Investments - UK Operations segment)
- ----------------------------------------------------
In October 2002 we announced that our ongoing energy trading operations would be
centered around our generation assets. As a result, we took steps to exit our
coal, gas and electricity trading activities in Europe, except for those
activities predominantly related to our U.K. generation operations. The Nordic
Trading business acquired earlier in 2002 was made available for sale to
potential buyers later in 2002. The estimated pre-tax loss on disposal recorded
in 2002 of $5.3 million, consisted of impairment of goodwill of $4.0 million and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments and Other Related Charges on our Consolidated
Statements of Operations. Management's determination of a zero fair value was
based on discussions with a potential buyer. The assets and liabilities of
Nordic Trading have been classified on our Consolidated Balance Sheets as held
for sale at December 31, 2002. The transfer of the Nordic Trading business,
including the trading portfolio, to new owners was completed during the second
quarter of 2003 and the impact on earnings during the second quarter of 2003 was
not significant.
Eastex (Investments - Other segment)
- ------------------------------------
In 1998, we began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, we requested that the FERC allow us 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, we solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. The estimated pre-tax loss on sale of $218.7 million pre-tax
($142 million after-tax), which was based on the estimated fair value of the
facility and indicative bids by interested buyers, was recorded in Discontinued
Operations in our Consolidated Statements of Operations during the fourth
quarter 2002.
We completed the sale of Eastex during the third quarter of 2003 and the effect
of the sale on third quarter 2003 results of operations was not significant. The
results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144 for all years presented. The assets and
liabilities of Eastex were reclassified on the Consolidated Balance Sheets from
Assets Held for Sale and Liabilities Held for Sale to Discontinued Operations at
December 31, 2002. See "Discontinued Operations" section of this note for
additional information.
Grupo Rede Investment (Investments - Other segment)
- ---------------------------------------------------
In December 2002, we recorded an other than temporary impairment totaling $141.0
million ($217.0 million net of federal income tax benefit of $76.0 million) of
our 44% equity investment in Vale and our 20% equity interest in Caiua, both
Brazilian electric operating companies (referred to as Grupo Rede). This amount
is included in Investment Value Losses on our Consolidated Statements of
Operations.
In December 2003 we transferred our share and investment in Vale to Grupo Rede
for $1 million. The effect of the transfer on fourth quarter results of
operations was not significant.
Excess Equipment (Investments - Other segment)
- ----------------------------------------------
In November 2002, as a result of a cancelled development project, we obtained
title to a surplus gas turbine generator. We had been unsuccessful in finding
potential buyers of the unit due to an over-supply of generation equipment
available for sale during 2002. An estimated pre-tax loss on disposal of $23.9
million was recorded in December 2002, based on market prices of similar
equipment. The loss is included in Asset Impairments and Other Related Charges
on our Consolidated Statements of Operations. The Other asset of $12 million in
2002 was classified on our Consolidated Balance Sheets as held for sale at
December 31, 2002.
We completed the sale of the surplus gas turbine generator in November 2003. The
proceeds from the sale were $8.7 million. A pre-tax loss of $1.8 million was
recorded in the fourth quarter of 2003.
Ft. Davis Wind Farm (Investments - Other segment)
- -------------------------------------------------
In the 1990's, we developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 our 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 is expected to be completed during 2004. An estimated pre-tax
loss on abandonment of $4.7 million was recorded in December 2002. The loss was
recorded in Asset Impairments and Other Related Charges on our Consolidated
Statements of Operations.
2002
- ----
SEEBOARD (Investments - Other segment)
- --------------------------------------
On June 18, 2002, through a wholly-owned subsidiary, we entered into an
agreement, subject to European Union (EU) approval, to sell our 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.
We 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. The
results of operations of SEEBOARD have been classified as Discontinued
Operations for all years presented. A net loss of $22 million pre-tax ($14
million after-tax) 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 goodwill 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 pre-tax ($38 million after-tax)
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. See "Discontinued Operations" section for the
total revenues and pretax profit (loss) of the discontinued operations of
SEEBOARD.
CitiPower (Investments - Other segment)
- ---------------------------------------
On July 19, 2002, through a wholly owned subsidiary, we entered into an
agreement to sell CitiPower, a retail electricity and gas supply and
distribution subsidiary in Australia. We 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. We recorded a pre-tax charge
totaling $192 million ($125 million after-tax) as of June 30, 2002. The charge
included a pre-tax impairment loss of $151 million ($98 million after-tax) on
the remaining carrying value of an intangible asset related to a distribution
license for CitiPower. The remaining $41 million pre-tax ($27 million after-tax)
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 Accounting Change retroactive to January 1, 2002.
The loss on the sale of CitiPower increased $37 million pre-tax ($24 million
after-tax) to $229 million pre-tax ($149 million after-tax; $122 million plus
$27 million of cumulative effect) in the second half of 2002 based on actual
closing amounts and exchange rates. See the "Discontinued Operations" section of
this note for the total revenues and pretax profit (loss) of the discontinued
operations of CitiPower.
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 ($73 million pre-tax).
In July 2001, through a wholly-owned subsidiary, we sold our 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, we 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 had a nominal impact on our results of operations and
cash flows.
In December 2001, we completed the sale of our 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. Subsequently
during 2002, due to decreasing market value of the shares received from the
sale, we reduced the value of them to zero.
DISCONTINUED OPERATIONS
- -----------------------
Management periodically assesses the overall AEP business model and makes
decisions regarding our continued support and funding of our various businesses
and operations. When it is determined that we will seek to exit a particular
business or activity and we have met the accounting requirements for
reclassification, we will reclassify the operations of those businesses or
operations as discontinued operations. The assets and liabilities of these
discontinued operations are classified as Assets and Liabilities Held for Sale
until the time that they are sold. At the time they are sold they are
reclassified to Assets and Liabilities of Discontinued Operations on the
Consolidated Balance Sheets for all periods presented. Assets and liabilities
that are held for sale, but do not qualify as a discontinued operations are
reflected as Assets and Liabilities Held for Sale both while they are held for
sale and after they have been sold, for all periods presented.
Certain of our operations were determined to be discontinued operations and have
been classified as such in 2003, 2002 and 2001. Results of operations of these
businesses have been reclassified as shown in the following table:
Pushan U.K.
SEE- Power Generation
BOARD CitiPower Eastex Plant LIG Plants Total
----- --------- ------ --------- --- ------------ -----
2003 Revenue $ - $ - $ 58 $ 60 $ 653 $ 125 $ 896
2003 Pretax Profit (Loss) - (20) (23) 4 (122) (713) (874)
2003 Earnings(Loss) After Tax 16 (13) (14) 4 (91) (507) (605)
2002 Revenue 694 204 73 57 507 251 1,786
2002 Pretax Profit (Loss) 180 (190) (239) (13) 14 (579) (827)
2002 Earnings (Loss) After Tax 96 (123) (156) (7) 8 (472) (654)
2001 Revenue 1,451 350 - 57 525 26 2,409
2001 Pretax Profit (Loss) 104 (4) 1 8 (6) (48) 55
2001 Earnings (Loss) After Tax 88 (6) - 4 (4) (41) 41
Assets and liabilities of discontinued operations have been reclassified as
follows:
Eastex
------
(in millions)
As of December 31, 2002
Current Assets $15
----
Total Assets of Discontinued Operations $15
====
Current Liabilities $ 8
Deferred Credits and Other 4
----
Total Liabilities of Discontinued Operations $12
====
Pushan Power Plant (Investments - Other segment)
- ------------------------------------------------
In the fourth quarter of 2002, we began active negotiations to sell our interest
in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest
partner and a purchase and sale agreement was signed in the fourth quarter of
2003. We expect to close on this transaction by mid 2004. An estimated pre-tax
loss on disposal of $20 million pre-tax ($13 million after-tax) was recorded in
December 2002, based on an indicative price expression. The estimated pre-tax
loss on disposal is classified in Discontinued Operations in our Consolidated
Statements of Operations.
Results of operations of Pushan have been reclassified as Discontinued
Operations. The assets and liabilities of Pushan have been classified on our
Consolidated Balance Sheets as held for sale. We have classified the assets and
liabilities as held for sale for longer than 12 months, which is longer than
originally expected, due to several unusual circumstances including the SARS
outbreak and governmental delays.
Louisiana Intrastate Gas (LIG ) (Investments - Gas Operations segment)
- ----------------------------------------------------------------------
After announcing during 2003 that we would be divesting our non-core assets we
began actively marketing LIG with the help of an investment advisor. After
receiving and analyzing initial bids during the fourth quarter 2003 we recorded
a $133.9 million pre-tax ($99 million after-tax) impairment loss; of this loss,
$128.9 million pre-tax relates to the impairment of goodwill and $5 million
pre-tax relates to other charges. In February 2004, we signed a definitive
agreement to sell the pipeline portion of LIG. We anticipate the sale will be
completed during the second quarter of 2004 and that the impact on results of
operations in 2004 will not be significant. The assets and liabilities of LIG
are classified as held for sale on our Consolidated Balance Sheets and the
results of operations (including the above-mentioned impairments and other
related charges) are classified in Discontinued Operations in our Consolidated
Statements of Operations.
U.K. Generation Plants (Investments - UK Operations segment)
- ------------------------------------------------------------
In December 2001, we 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 our own projections made during the
fourth quarter of 2002 indicated 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 ($414 million after-tax). This
impairment loss is included in 2002 Discontinued Operations on our Consolidated
Statements of Operations.
Management has retained an investment advisor to assist in determining the best
methodology to exit the U.K. business. An information memorandum was distributed
for the sale of our U.K. Generation and based on current information we recorded
a $577 million pre-tax charge ($375 after-tax), including asset impairments of
$420.7 million during the fourth quarter of 2003 to write down the value of the
assets to their estimated realizable value. Additional charges of $156.7 million
pre-tax were also recorded in December 2003 including $122.2 million related to
the net loss on certain cash flow hedges previously recorded in Accumulated
Other Comprehensive Income that has been reclassified into earnings as a result
of management's determination that the hedged event is no longer probable of
occurring and $34.5 million related to a first quarter 2004 sale of certain
power contracts. The assets and liabilities of U.K. Generation have been
classified as held for sale on our Consolidated Balance Sheets and the results
of operations are included in Discontinued Operations on our Consolidated
Statements of Operations. We anticipate the sale of the U.K. Generation plants
during 2004.
ASSET IMPAIRMENTS, INVESTMENT VALUE LOSSES AND OTHER RELATED CHARGES
- --------------------------------------------------------------------
In 2003, AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.4 billion [consisting of approximately $650 million
related to Asset Impairments ($610 million) and Other Related Charges ($40
million), $70 million related to Investment Value Losses, $711 million related
to Discontinued Operations ($550 million of impairments and $161 million of
other charges) and $6 million related to charges recorded for Excess Real Estate
in Maintenance and Other Operation in the Consolidated Statements of Operations]
that reflected downturns in energy trading markets, projected long-term
decreases in electricity prices, our decision to exit non-core businesses and
other factors.
In 2002, AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.7 billion (consisting of approximately $318 million
related to Asset Impairments, $321 million related to Investment Value Losses,
$938 million related to Discontinued Operations and $88 million related to
charges recorded in other lines within the Consolidated Statements of
Operations) that reflected downturns in energy trading markets, projected
long-term decreases in electricity prices, and other factors. These impairments
exclude the transitional goodwill impairment loss from adoption of SFAS 142 (see
Notes 2 and 3).
The categories of impairments include:
2003 2002 2001
---- ---- ----
(in millions)
Asset Impairments and Other Related Charges (Pre-tax)
- -----------------------------------------------------
AEP Coal $ 67 $ 60 $ -
HPL and Other 315 - -
Power Generation Facility 258 - -
Blackhawk Coal Company 10 - -
Ft. Davis Wind Farm - 5 -
Texas Plants - 38 -
Newgulf Facility - 12 -
Excess Equipment - 24 -
Nordic Trading - 5 -
Excess Real Estate - 16 -
Telecommunications - AEPC/C3 - 158 -
------ ------ -----
Total $ 650 $ 318 $ -
====== ====== =====
Investment Value Losses (Pre-tax)
- ---------------------------------
Independent Power Producers $ 70 $ - $ -
Water Heater Assets - 3 -
South Coast Power Investment - 63 -
Telecommunications - AFN - 14 -
AEP Gas Power Systems - 12 -
Grupo Rede Investment - Vale - 217 -
Technology Investments - 12 -
------ ------ -----
Total $ 70 $ 321 $ -
====== ====== =====
"Impairments and Other Related Charges" and
"Operations" Included in Discontinued Operations (After-tax)
- ------------------------------------------------------------
Impairments and Other Related Charges:
U.K. Generation Plants $(375) $(414) $ -
Louisiana Intrastate Gas (99) - -
CitiPower - (122) -
Eastex - (142) -
SEEBOARD - 24 -
Pushan - (13) -
------ ------ -----
Total* (474) (667) -
------ ------ -----
Operations:
U.K. Generation Plants (132) (58) (41)
Louisiana Intrastate Gas 8 8 (4)
CitiPower (13) (1) (6)
Eastex (14) (14) -
SEEBOARD 16 72 88
Pushan 4 6 4
------ ------ -----
Total (131) 13 41
------ ------ -----
Total Discontinued Operations $(605) $(654) $ 41
====== ====== =====
* See the "Dispositions" and "Discontinued Operations" sections of this note
for the pre-tax impairment figures.
ASSETS HELD FOR SALE
- --------------------
Telecommunications (Investments - Other segment)
- ------------------------------------------------
We developed businesses to provide telecommunication services to businesses and
other telecommunication companies through broadband fiber optic networks. The
businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN, LLC (AFN), a joint venture. Due to the difficult
economic conditions in these businesses and the overall telecommunications
industry, the AEP Board approved in December 2002 a plan to cease operations of
these businesses. We took steps to market the assets of the businesses to
potential interested buyers in the fourth quarter of 2002.
We completed the sale of substantially all the assets of C3 in the first quarter
of 2003 as discussed in the "Dispositions" section of this note. AFN closed on
the sale of substantially all of its assets in January 2004 with no significant
additional effect on results of operations in 2004. The sale of remaining
telecommunication assets is proceeding.
An estimated pre-tax impairment loss of $158.5 million ($76.3 million related to
AEPC and $82.2 million related to C3) was recorded in December 2002 and is
classified in Asset Impairments and Other Related Charges in our Consolidated
Statements of Operations. An estimated pre-tax loss in value of the investment
in AFN of $13.8 million was recorded in December 2002 and is classified in
Investment Value Losses in our Consolidated Statements of Operations. The
estimated losses were based on indicative bids by potential buyers. Property,
Plant and Equipment, net of accumulated depreciation, of the telecommunication
businesses have been classified on our Consolidated Balance Sheets as held for
sale in 2002.
AEP Coal (Investments - Other segment)
- --------------------------------------
In October 2001, we acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and renamed "AEP Coal." During 2002 the coal operations suffered from a
decline in prices and adverse mining factors resulting in 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 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 and Other Related Charges on
our Consolidated Statements of Operations.
In 2003, as a result of management's decision to exit our non-core businesses,
we retained an advisor to facilitate the sale of AEP Coal. In the fourth quarter
of 2003, after considering the current bids and all other options, we recorded a
$66.6 million pre-tax ($43.6 million after-tax) charge comprised of a $29.4
million asset impairment, a $25.2 million charge related to accelerated
remediation cost accruals and $12 million charge (accrued at December 31, 2003)
related to a royalty agreement. These impairment losses were included in Asset
Impairments and Other Related Charges on our Consolidated Statements of
Operations. The assets and liabilities of AEP Coal that are held for sale have
been included in Assets and Liabilities Held for Sale in our Consolidated
Balance Sheets at December 31, 2003 and 2002.
Texas Plants (Utility Operations segment)
- -----------------------------------------
In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired
power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted
reliability studies, which determined that seven plants (4 TCC plants and 3 TNC
plants) would be required to ensure reliability of the electricity grid. As a
result of those studies, ERCOT and AEP mutually agreed to enter into reliability
must run (RMR) agreements, which expired in December 2002, and were subsequently
renewed through December 2003. However, certain contractual provisions provided
ERCOT with a 90-day termination clause, if the contracted facility was no longer
needed to ensure reliability of the electricity grid. With ERCOT's approval, AEP
proceeded with its planned deactivation of the remaining nine plants. In August
2003, pursuant to contractual terms, ERCOT provided notification to AEP of its
intent to cancel a RMR agreement at one of the TNC plants. Upon termination of
the agreement, AEP proceeded with its planned deactivation of the plant. In
December 2003, AEP and ERCOT mutually agreed to new RMR contracts at six plants
(4 TCC plants and 2 TNC plants) through December 2004, subject to ERCOT's 90 day
termination clause and the divestiture of the TCC facilities.
As a result of the decision to deactivate TNC plants, a write-down of utility
assets of approximately $34.2 million (pre-tax) was recorded in Asset
Impairments and Other Related Charges expense during the third quarter 2002 on
our Consolidated Statements of Operations. The decision to deactivate the TCC
plants resulted in a write-down of utility assets of approximately $95.6 million
(pre-tax), which was deferred and recorded in Regulatory Assets during the third
quarter 2002 in our Consolidated Balance Sheets.
During the fourth quarter of 2002, evaluations continued as to whether assets
remaining at the deactivated 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 and Other Related Charges expense of $3.9 million (pre-tax) in the
fourth quarter of 2002. In addition, TNC recorded related fuel inventory and
materials and supplies write-downs of $2.6 million ($1.2 million in Fuel for
Electric Generation and $1.4 million in Maintenance and Other Operation).
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 of 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 pre-tax in 2002 (all
related to TNC) is included in Asset Impairments and Other Related Charges in
our Consolidated Statements of Operations.
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 deactivated or designated as RMR status.
During the fourth quarter of 2003, after receiving bids from interested buyers,
we recorded a $938 million impairment loss and changed the classification of the
plant assets from plant in service to Assets Held for Sale. In accordance with
Texas legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires charge,
subject to the final outcome of the 2004 Texas true-up proceeding. See Texas
Restructuring section of Note 6, "Customer Choice and Industry Restructuring,"
for further discussion of the divestiture plan, anticipated timeline and true-up
proceeding.
The assets and liabilities of the entities held for sale at December 31, 2003
and 2002 are as follows:
Pushan U.K.
Power Generation AEP Texas
Plant Plants Coal Plants LIG Total
------- ---------- ---- ------ ---- -----
December 31, 2003
- ------------------ (in millions)
Assets:
Current Assets $ 24 $1,245 $ 6 $ 57 $ 50 $1,382
Property, Plant and Equipment, Net 142 99 13 797 171 1,222
Regulatory Assets - - - 49 - 49
Spent Nuclear Fuel and
Decommissioning Trusts - - - 125 - 125
Goodwill - - - - 15 15
Long-term Risk Management Assets - 274 - - - 274
Other - 6 - - 9 15
----- ------- ---- ------- ----- -------
Total Assets Held for Sale $166 $1,624 $19 $1,028 $245 $3,082
===== ======= ==== ======= ===== =======
Liabilities:
Current Liabilities $ 26 $ 988 $ - $ - $ 61 $1,075
Long-term Debt 20 - - - - 20
Long-term Risk Management
Liabilities - 435 - - - 435
Regulatory Liabilities and Deferred
Investment Tax Credits - - - 9 - 9
Asset Retirement Obligations and
Nuclear Decommissioning Trusts - 29 - 219 - 248
Employee Benefits and Pension
Obligations - 12 - - - 12
Deferred Credits and Other 57 - 14 - 6 77
----- ------- ---- ------- ----- -------
Total Liabilities Held for Sale $103 $1,464 $14 $ 228 $ 67 $1,876
===== ======= ==== ======= ===== =======
Pushan U.K. Tele- Water
Power Generation AEP Texas Commun- Nordic Newgulf Excess Heater
Plant Plants Coal Plants LIG ications Trading Facility Equipment Program Total
----- ---------- ---- ------ --- -------- ------- -------- --------- ------- -----
December 31, 2002 (in millions)
- ------------------
Assets:
Current Assets $ 19 $ 571 4 $ 70 $ 62 $- $35 $- $ - $ 1 $ 762
Property, Plant and
Equipment, Net 132 445 38 1,647 169 6 - 6 - 38 2,481
Spent Nuclear Fuel
and Decommissioning
Trusts - - - 98 - - - - - - 98
Goodwill - 11 - - 144 - - - - - 155
Long-term Risk
Management Assets - 61 - - - - 5 - - - 66
Other - 22 - - - - 5 - 12 - 39
----- ------- ---- ------- ----- --- ---- --- ---- ---- -------
Total Assets
Held for Sale $151 $1,110 $42 $1,815 $375 $6 $45 $6 $12 $39 $3,601
===== ======= ==== ======= ===== === ==== === ==== ==== =======
Liabilities:
Current Liabilities $ 28 $ 992 $ - $ - $ 53 $- $48 $- $ - $ - $1,121
Long-term Debt 25 - - - - - - - - - 25
Deferred Income Taxes - - - - - - - - - - -
Long-term Risk
Management
Liabilities - 39 - - 7 - 3 - - - 49
Deferred Credits and
Other 26 24 15 9 10 - - - - - 84
----- ------- ---- ------- ----- --- ---- --- ---- ---- -------
Total Liabilities
Held for Sale $ 79 $1,055 $15 $ 9 $ 70 $- $51 $- $ - $ - $1,279
===== ======= ==== ======= ===== === ==== === ==== ==== =======
ASSETS HELD AND USED
- --------------------
In 2003 and 2002, we recorded the following impairments related to assets
(including Goodwill) held and used to Asset Impairments and Other Related
Charges on our Consolidated Statements of Operations as discussed below:
Excess Real Estate (Investments - Other segment)
- ------------------------------------------------
In the fourth quarter of 2002, we began to market an under-utilized office
building in Dallas, TX obtained through our merger with CSW. Sale of the
facility was projected by the second quarter 2003 and an estimated pre-tax loss
on disposal of $15.7 million was recorded in 2002, based on the option sale
price. The estimated loss is included in Asset Impairments and Other Related
Charges on our Consolidated Statements of Operations. The Property asset of $18
million in 2002 and $36 million in 2001 was previously classified on our
Consolidated Balance Sheets as held for sale.
The sale of this office building was not completed by the end of 2003 and as a
result the building no longer qualifies for held for sale status. In accordance
with SFAS 144 the building will be moved to held and used status for all periods
presented as of December 31, 2003. In December 2003 we recorded an additional
pre-tax impairment of $6 million based on bids received to date. The impairment
is recorded in Maintenance and Other Operation on our Consolidated Statements of
Operations. The building will continue to be actively marketed.
HPL and Other (Investments - Gas Operations segment)
- ----------------------------------------------------
HPL owns, or leases, and operates natural gas gathering, transportation and
storage operations in Texas. In 2003, management announced that we were in the
process of divesting our non-core assets, which includes the assets within our
Investments-Gas Operations segment. During the fourth quarter of 2003, based on
a probability-weighted after-tax cash flow analysis of the fair value of HPL, we
recorded an impairment of $300 million pre-tax ($218 million after-tax), with
$150 million pre-tax related to goodwill, reflecting management's decision not
to operate HPL as a major trading hub and market indicators supported by the LIG
bid process. The cash flow analysis used management's estimate of the
alternative likely outcomes of the uncertainties surrounding the continued use
of the Bammel facility and other matters (see Note 7) and an after-tax risk free
discount rate of 3.3% over the remaining life of the assets.
We also recorded a $15 million pre-tax charge ($10 million after-tax) in the
fourth quarter 2003 included in Asset Impairments and Other Related Charges on
our Consolidated Statements of Operations. This charge related to the effect of
the write-off of certain HPL and LIG assets and the impairment of goodwill
related to our former optimization strategy of LIG assets by AEP Energy
Services.
Blackhawk Coal Company (Utility Operations segment)
- ---------------------------------------------------
Blackhawk Coal Company (Blackhawk) is a wholly-owned subsidiary of I&M and was
formerly engaged in coal mining operations until they ceased due to gas
explosions in the mine. During the fourth quarter of 2003, it was determined
that the carrying value of the investment was impaired based on an updated
valuation reflecting management's decision not to pursue development of
potential gas reserves. As a result, a $10.4 million pre-tax charge was recorded
to reduce the value of the coal and gas reserves to their estimated realizable
value. This charge was recorded in Asset Impairments and Other Related Charges
in our Consolidated Statements of Operations.
Power Generation Facility (Investments - Other segment)
- -------------------------------------------------------
We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. Juniper will own the Facility and lease it to AEP after construction is
completed and we will sublease the Facility to The Dow Chemical Company (Dow).
At December 31, 2002, we would have reported the Facility and related
obligations as an operating lease upon achieving commercial operation. In the
fourth quarter of 2003, we chose to not seek funding from Juniper for budgeted
and approved pipeline construction costs related to the Facility. In order to
continue reporting the Facility as an off-balance sheet financing, we were
required to seek funding of our construction costs from Juniper. As a result, we
recorded $496 million of construction work in progress (CWIP) and the related
financing liability for the debt and equity as of December 31, 2003. At December
31, 2003, the lease of the Facility is reported as an owned asset under a lease
financing transaction. Since the debt obligations of the Facility are recorded
on our financial statements, the obligations under the lease agreement are
excluded from the above table of future minimum lease payments.
The current litigation between TEM and ourselves, combined with a substantial
oversupply of generation capacity in the markets where we would otherwise sell
the power freed up by TEM contract termination, triggered us to review the
project for possible impairment of its reported values. We determined that the
value of the Facility was impaired and recorded a $258 million pre-tax
impairment ($168 million after-tax) in December 2003 on the CWIP.
See further discussion in Notes 7 and 16.
INVESTMENT VALUE AND OTHER LOSSES
- ---------------------------------
In 2003 and 2002, we recorded the following declines in fair value on
investments:
Independent Power Producers (Investments - Other segment)
- ---------------------------------------------------------
During the third quarter of 2003, we initiated an effort to sell four domestic
Independent Power Producer (IPP) investments accounted for under the equity
method. Based on indicative bids, it was determined that an other than temporary
impairment existed on two of the equity investments. The impairment was the
result of the measurement of fair value that was triggered by our recent
decision to sell the assets. A $70.0 million pre-tax ($45.5 million net of tax)
loss was recorded in September 2003 as a result of an other than temporary
impairment of the equity interest. This loss of investment value is included in
Investment Value Losses on our Consolidated Statements of Operations. We have
received bids on the IPP investments and anticipate a final sale during the
first half of 2004.
South Coast Power Investment (Investments - Other segment)
- ----------------------------------------------------------
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 Plants above in "Discontinued Operations." 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 Losses on our
Consolidated Statements of Operations in 2002.
Technology Investments (Investments - Other segment)
- ----------------------------------------------------
We 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 Losses on our Consolidated Statements of
Operations.
11. BENEFIT PLANS
- ------------------
In the U.S. we sponsor two qualified pension plans and two nonqualified pension
plans. A substantial majority of our employees in the U.S. are covered by either
one qualified plan or both a qualified and a nonqualified pension plan. Other
postretirement benefit plans are sponsored by us to provide medical and death
benefits for retired employees in the U.S.
We also have a foreign pension plan for employees of AEP Energy Services U.K.
Generation Limited (Genco) in the U.K. The Genco pension plan had $7 million of
accumulated benefit obligations in excess of plan assets at December 31, 2002.
The plan was in an overfunded position at December 31, 2003.
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 at
the plan's measurement date of December 31, 2003, and a statement of the funded
status as of December 31 for both years:
U.S.
U.S. Other Post Retirement
Pension Plans Benefit Plans
------------- ---------------------
2003 2002 2003 2002
---- ---- ---- ----
Change in Benefit Obligation: (in millions)
Obligation at January 1 $3,583 $3,292 $ 1,877 $ 1,645
Service Cost 80 72 42 34
Interest Cost 233 241 130 114
Participant Contributions - - 14 13
Plan Amendments - (2) - -
Actuarial (Gain) Loss 91 258 192 152
Benefit Payments (299) (278) (92) (81)
------- ------- -------- --------
Obligation at December 31 $3,688 $3,583 $ 2,163 $ 1,877
======= ======= ======== ========
Change in Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1 $2,795 $3,438 $ 723 $ 711
Actual Return on Plan Assets 619 (371) 122 (57)
Company Contributions (a) 65 6 183 137
Participant Contributions - - 14 13
Benefit Payments (a) (299) (278) (92) (81)
------- ------- -------- --------
Fair Value of Plan Assets at December, 31 $3,180 $2,795 $ 950 $ 723
======= ======= ======== ========
Funded Status:
Funded Status at December 31 $ (508) $ (788) $(1,213) $(1,154)
Unrecognized Net Transition (Asset) Obligation 2 (7) 206 233
Unrecognized Prior Service Cost (12) (13) 6 6
Unrecognized Actuarial (Gain) Loss 797 1,020 977 896
------- ------- -------- --------
Net Asset (Liability) Recognized $ 279 $ 212 $ (24) $ (19)
======= ======= ======== ========
(a) Our contributions and benefit payments include only those amounts
contributed directly to or paid directly from plan assets.
Accumulated Benefit Obligation: 2003 2002
---- ----
(in millions)
U.S. Qualified Pension Plans $3,549 $3,456
U.S. Nonqualified Pension Plans 76 71
U.S.
U.S. Other Post Retirement
Pension Plans Benefit Plans
------------------- ------------------
2003 2002 2003 2002
---- ---- ---- ----
(in millions)
Prepaid Benefit Costs $ 325 $ 255 $ - $ -
Accrued Benefit Liability (46) (44) (24) (19)
Additional Minimum Liability (723) (944) N/A N/A
Unrecognized Prior Service Costs 39 45 N/A N/A
Accumulated Other Comprehensive Income 684 900 N/A N/A
------ ------ ----- ----
Net Asset (Liability) Recognized $ 279 $ 212 $(24) $(19)
====== ====== ===== =====
Increase (Decrease) in Minimum Liability
Included in Other Comprehensive Income (Pre-tax) $(216) $ 894 N/A N/A
====== ====== ===== =====
N/A = Not Applicable
The asset allocations for our U.S. pension plans at the end of 2003 and 2002,
and the target allocation for 2004, by asset category, are as follows:
Target Allocation Percentage of Plan Assets at Yearend
----------------- ------------------------------------
Asset Category 2004 2003 2002
-------------- ---- ---- ----
(in percentage)
Equity 70 71 67
Fixed Income 28 27 32
Cash and Cash Equivalents 2 2 1
---- ---- ----
Total 100 100 100
==== ==== ====
The asset allocations for our U.S. other postretirement benefit plans at the
end of 2003 and 2002, and target allocation for 2004, by asset category, are as
follows:
Target Allocation Percentage of Plan Assets at Yearend
----------------- ------------------------------------
Asset Category 2004 2003 2002
-------------- ---- ---- ----
(in percentage)
Equity 70 61 41
Fixed Income 28 36 38
Cash and Cash Equivalents 2 3 21
---- ---- ----
Total 100 100 100
==== ==== ====
Our investment strategy for our employee benefit trust funds is to use a
diversified mixture of equity and fixed income securities to preserve the
capital of the funds and to maximize the investment earnings in excess of
inflation within acceptable levels of risk.
The value of our qualified plans' assets increased from $2.795 billion at
December 31, 2002 to $3.180 billion at December 31, 2003. The qualified plans
paid $292 million in benefits to plan participants during 2003 (nonqualified
plans paid $7 million in benefits). The status of our plans remains in an
underfunded position (plan assets are less than projected benefit obligations)
of $508 million at December 31, 2003. Due to the pension plans currently being
underfunded, we recorded income in Other Comprehensive Income (OCI) of $154
million, and a reduction in the Deferred Income Tax Asset of $76 million, offset
by a reduction to Minimum Pension Liability of $234 million and a reduction in
adjustments for unrecognized costs of $4 million. The charge to OCI does not
affect earnings or cash flow. Also, due to the current underfunded status of our
qualified plans, we expect to make cash contributions to our U.S. pension plans
of approximately $41 million in 2004.
At December 31, 2003 and 2002, the projected benefit obligation, accumulated
benefit obligation, and fair value of U.S. plan assets of the U.S. pension plans
with an accumulated benefit obligation in excess of plan assets, were as
follows:
U.S. Plans
----------
End of Year 2003 2002
- ----------- -------- --------
(in millions)
Projected Benefit Obligation $3,688 $3,583
Accumulated Benefit Obligation 3,625 3,527
Fair Value of Plan Assets 3,180 2,795
Accumulated Benefit Obligation
Exceeds the Fair Value of Plan Assets 445 732
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.
The weighted-average assumptions as of December 31, used in the measurement of
our benefit obligations are shown in the following tables:
U.S.
U.S. Other Postretirement
Pension Plans Benefit Plans
------------- --------------------
2003 2002 2003 2002
---- ---- ---- ----
(in percentages)
Discount Rate 6.25 6.75 6.25 6.75
Rate of Compensation Increase 3.7 3.7 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 2003, we determined that a decrease in
our discount rate from 6.75% at December 31, 2002 to 6.25% at December 31, 2003
was appropriate.
The rate of compensation increase assumed varies with the age of the employee,
ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.
Information about the expected cash flows for the U.S. pension (qualified and
non-qualified) and other postretirement benefit plans is as follows:
U.S.
Other Postretirement
U.S. Pension Plans Benefit Plans
------------------ --------------------
(in millions)
Employer Contributions
2003 $65 $183
2004 (expected) 41 180
The table below reflects the total benefits expected to be paid from the plan or
from our assets, including both our share of the benefit cost and the
participants' share of the cost, which is funded by participant contributions to
the plan. Future benefit payments are dependent on the number of employees
retiring, whether the retiring employees elect to receive pension benefits as
annuities or as lump sum distributions, future integration of the benefit plans
with changes to Medicare and other legislation, future levels of interest rates,
and variances in actuarial results. The estimated payments for pension benefits
and other postretirement benefits are as follows:
U.S.
U.S. Other Postretirement
Pension Benefits Benefit Plans
---------------- --------------------
(in millions)
2004 $293 $106
2005 300 114
2006 310 123
2007 325 132
2008 335 140
Years 2009 to 2013, in Total 1,840 836
The contribution to the pension fund is based on the minimum amount required by
the U.S. Department of Labor or the amount of the pension expense for accounting
purposes, whichever is greater. The contribution to the other postretirement
benefit plans' trusts is generally based on the amount of the other
postretirement benefit plans' expense for accounting purposes and is provided
for in agreements with state regulatory authorities.
The following table provides the components of our net periodic benefit cost
(credit) for the plans for fiscal years 2003, 2002 and 2001:
U.S. U.S.
Pension Plans Other Postretirement Benefit Plans
------------- ----------------------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
(in millions)
Service Cost $ 80 $ 72 $ 69 $ 42 $ 34 $ 30
Interest Cost 233 241 232 130 114 114
Expected Return on Plan Assets (318) (337) (338) (64) (62) (61)
Amortization of Transition
(Asset) Obligation (8) (9) (8) 28 29 30
Amortization of Prior-service Cost (1) (1) - - - -
Amortization of Net Actuarial
(Gain) Loss 11 (10) (24) 52 27 18
------ ------ ------ ----- ----- -----
Net Periodic Benefit Cost (Credit) (3) (44) (69) 188 142 131
Curtailment Loss - - - - - 1
------ ------ ------ ----- ----- -----
Net Periodic Benefit Cost (Credit)
After Curtailments $ (3) $ (44) $ (69) $188 $142 $132
====== ====== ====== ===== ===== =====
The weighted-average assumptions as of January 1, used in the measurement of our
benefit costs are shown in the following tables:
U.S. U.S.
Pension Plans Other Postretirement Benefit Plans
------------- ----------------------------------
2003 2002 2001 2003 2002 2001
---- ---- ---- ---- ---- ----
(in percentage)
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
The expected return on plan assets for 2003 was determined by evaluating
historical returns, the current investment climate, rate of inflation, and
current prospects for economic growth. After evaluating the current yield on
fixed income securities as well as other recent investment market indicators,
the expected return on plan assets was reduced to 8.75% for 2004. The expected
return on other postretirement benefit plan assets (a portion of which is
subject to capital gains taxes as well as Unrelated Business Income Taxes) was
reduced to 8.35%.
The assumptions used for other postretirement benefit plan measurement purposes
are shown below:
Health Care Trend Rates: 2003 2002
------ ------
(in percentage)
Initial 10.0 10.0
Ultimate 5.0 5.0
Year Ultimate Reached 2008 2008
Assumed health care cost trend rates have a significant effect on the amounts
reported for the other postretirement benefit 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 $ 26 $ (21)
Effect on the Health Care Component of the
Accumulated Postretirement Benefit Obligation 315 (257)
We have not yet determined the impact of the Medicare Prescription Drug
Improvement and Modernization Act of 2003 on our other postretirement benefit
plans' accumulated benefit obligation and periodic benefit cost. See FASB Staff
Position No. 106-1 in Note 2 for additional information on the potential impact
on our results of operations, cash flows and financial condition.
AEP Savings Plans
- -----------------
We sponsor 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. On January 1, 2003, the two
major AEP Savings Plans merged into a single plan. Beginning in 2001, and
continuing under the single merged plan, our contributions to the plans
increased from 50% to 75% of the first 6% of eligible employee compensation. The
cost for contributions to these plans totaled $57.0 million in 2003, $60.1
million in 2002 and $55.6 million in 2001.
Other UMWA Benefits
- -------------------
We provide UMWA pension, health and welfare benefits for certain unionized
mining employees, retirees, and their survivors who meet eligibility
requirements. UMWA trustees make final interpretive determinations with regard
to all benefits. The pension benefits are administered by UMWA trustees and
contributions are made to their trust funds.
The health and welfare benefits are administered by us and benefits are paid
from our general assets. Contributions are expensed as paid as part of the cost
of active mining operations and were not material in 2003, 2002 and 2001.
12. STOCK-BASED COMPENSATION
- ------------------------------
The American Electric Power System 2000 Long-Term Incentive Plan (the Plan)
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 by the Board of Directors and
shareholders.
Stock-based compensation awards granted by AEP include restricted stock units,
restricted shares, performance share units and stock options. Restricted stock
units vest, subject to the participant's continued employment, in approximately
equal 1/3 increments on January 1st for three years following the grant date.
Amounts equivalent to cash dividends on the units accrue as additional units.
AEP awarded 105,910 restricted stock units, including dividends, in 2003, with a
weighted-average grant-date fair value of $22.17 per unit. Compensation cost is
recorded over the vesting period, based on the market value on the grant date.
Expense associated with units that are forfeited is reversed in the period of
forfeiture.
AEP awarded 300,000 restricted shares in January 2004, which vest over periods
ranging from 1 to 8 years. Compensation cost will be recorded over the vesting
period based on the market value of $30.76 per unit on the grant date.
Performance share units are equal in value to shares of AEP common stock but are
subject to an attached performance factor ranging from 0% to 200%. The
performance factor is determined at the end of the performance period based on
performance measure(s) established for each grant at the beginning of the
performance period by the Human Resources Committee of the Board of Directors.
Performance share units are typically paid in cash at the end of a three-year
vesting period, unless they are needed to satisfy a participant's stock
ownership requirement, in which case they are mandatorily deferred as phantom
stock units until the end of the participants AEP career. Phantom stock units
have a value equivalent to AEP common stock and are typically paid in cash upon
the participant's termination of employment. The compensation cost for
performance share units is recorded over the vesting period and both the
performance share and phantom stock unit liability is adjusted for changes in
fair market value. Amounts equivalent to cash dividends on both performance
share and phantom stock units accrue as additional units.
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, and in
accordance with its policy, AEP does not record compensation expense. 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 1 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 AEP stock option transactions in fiscal periods 2003, 2002 and 2001
is as follows:
2003 2002 2001
---------------------------- ---------------------------- ----------------------------
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 8,787 $ 34 6,822 $37 6,610 $ 36
Granted 927 $ 28 2,923 $27 645 $ 45
Exercised (23) $ 27 (600) $36 (216) $ 38
Forfeited (597) $ 33 (358) $41 (217) $ 37
------ ------ ------
Outstanding at end of year 9,094 $ 33 8,787 $34 6,822 $ 37
====== ====== ======
Options exercisable
at end of year 3,909 $ 36 2,481 $36 395 $ 43
====== ====== ======
Weighted average exercise price of options:
-Granted above Market Price N/A $27 N/A
-Granted at Market Price $ 28 $27 $ 45
The following table summarizes information about AEP stock options outstanding
at December 31, 2003:
Options Outstanding
-------------------
Weighted Average Weighted Average
Range of Exercise Prices Number Outstanding Remaining Life Exercise Price
------------------------ ------------------ -------------- --------------
(in thousands) (in years)
$25.73 - $27.95 3,530 9.1 $27.28
$34.58 - $41.50 5,054 6.6 $35.74
$43.79 - $49.00 510 7.5 $45.98
------
9,094 7.6 $33.03
======
Options Exercisable
-------------------
Weighted Average
Range of Exercise Prices Number Outstanding Exercise Price
------------------------ ------------------ --------------
(in thousands)
$25.73 - $27.95 52 $27.06
$34.58 - $41.50 3,610 $35.78
$43.79 - $49.00 247 $46.57
------
3,909 $36.35
======
The proceeds received from exercised stock options are included in common stock
and paid-in capital.
The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used to estimate the fair value of AEP options granted:
2003 2002 2001
---- ---- -----
Risk Free Interest Rate 3.92% 3.53% 4.87%
Expected Life 7 years 7 years 7 years
Expected Volatility 27.57% 29.78% 28.40%
Expected Dividend Yield 4.86% 6.15% 6.05%
Weighted average fair value of options:
-Granted above Market Price N/A $4.58 N/A
-Granted at Market Price $5.26 $4.37 $8.01
13. BUSINESS SEGMENTS
- ----------------------
Our segments and their related business activities are as follows:
Utility Operations
.. Domestic generation of electricity for sale to retail and wholesale
customers
.. Domestic electricity transmission and distribution
Investments - Gas Operations*
.. Gas pipeline and storage services
Investments - UK Operations**
.. International generation of electricity for sale to wholesale customers
.. Coal procurement and transportation to AEP plants and third parties
Investments - Other
.. Coal mining, bulk commodity barging operations and other energy supply
businesses
* Operations of Louisiana Intrastate Gas were classified as discontinued
during 2003.
** UK Operations were classified as discontinued during 2003.
The tables below present segment information for the twelve months ended
December 31, 2003, 2002 and 2001. These amounts include certain estimates and
allocations where necessary. Prior year amounts have been reclassified to
conform to the current year's presentation.
Investments
---------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
2003 (in millions)
- ----
Revenues from:
External Customers $10,871 $3,097 $ - $ 577 $ - $ - $14,545
Other Operating Segments - 192 - 96 11 (299) -
Discontinued Operations,
Net of Tax - (91) (507) (7) - - (605)
Cumulative Effect of
Accounting Changes,
Net of Tax 237 (23) (21) - - - 193
Net Income (Loss) 1,455 (404) (528) (284) (129) - 110
Depreciation, Depletion and
Amortization Expense 1,241 18 - 39 1 - 1,299
Total Assets 30,816 2,405 1,705 1,697 14,925 (14,804) 36,744
Assets Held for Sale 1,033 240 1,624 185 - - 3,082
Investments in Equity
Method Subsidiaries - 36 38 87 - - 161
Gross Property Additions 1,323 25 - 10 - - 1,358
* All Other includes interest, litigation and other miscellaneous parent
company expenses, as well as the operations of a service company subsidiary,
which provides services at cost to the other operating segments.
Investments
----------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
2002 (in millions)
- ----
Revenues from:
External Customers $10,446 $2,071 $ - $ 791 $ - $ - $13,308
Other Operating Segments - 222 - 147 10 (379) -
Discontinued Operations,
Net of Tax - 8 (472) (190) - - (654)
Cumulative Effect of
Accounting Changes,
Net of Tax - - - (350) - - (350)
Net Income (Loss) 1,154 (91) (472) (1,062) (48) - (519)
Depreciation, Depletion and
Amortization Expense 1,268 13 - 67 - - 1,348
Total Assets 29,431 3,912 1,215 1,947 18,388 (19,003) 35,890
Assets Held for Sale 1,866 375 1,150 210 - - 3,601
Investments in Equity
Method Subsidiaries - 35 - 137 - - 172
Gross Property Additions 1,517 47 - 25 96 - 1,685
* All Other includes interest, litigation and other miscellaneous parent company
expenses, as well as the operations of a service company subsidiary, which
provides services at cost to the other operating segments.
Investments
-----------------------------------
Utility Gas UK All Reconciling
Operations Operations Operations Other Other* Adjustments Consolidated
---------- ---------- ---------- ----- ------ ----------- ------------
2001 (in millions)
- ----
Revenues from:
External Customers $10,546 $1,797 $ - $410 $ - $ - $12,753
Other Operating Segments - - - 86 5 (91) -
Discontinued Operations,
Net of Tax - (4) (41) 86 - - 41
Extraordinary Items,
Net of Tax (48) - - - - - (48)
Cumulative Effect,
Net of Tax - - - 18 - - 18
Net Income (Loss) 911 87 (41) 86 (72) - 971
Depreciation, Depletion and
Amortization Expense 1,193 15 - 25 - - 1,233
Gross Property Additions 1,397 14 - 137 98 - 1,646
* All Other includes interest, litigation and other miscellaneous parent company
expenses, as well as the operations of a service company subsidiary, which
provides services at cost to the other operating segments.
14. DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS
- ---------------------------------------------------
DERIVATIVES AND HEDGING
- -----------------------
In the first quarter of 2001, we adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. We recorded a favorable
transition adjustment to Accumulated Other Comprehensive Income (Loss) 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 transition adjustment were designated as cash flow
hedges and relate to foreign operations.
SFAS 133 requires recognition of all derivative instruments as either assets or
liabilities in the statement of financial position at fair value. Our accounting
for the changes in the fair value of a derivative instrument depends on whether
it qualifies, and has been designated, as part of a hedging relationship and
further, on the type of hedging relationship. We designate the hedging
instrument, based on the exposure being hedged, as a fair value hedge, a cash
flow hedge or a hedge of a net investment in a foreign operation. Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in SFAS 133. These contracts are not reported
at fair value, as otherwise required by SFAS 133.
For fair value hedges (i.e. hedging the exposure to changes in the fair value of
an asset, liability or an identified portion thereof that is attributable to a
particular risk), we recognize the gain or loss on the derivative instrument as
well as the offsetting loss or gain on the hedged item associated with the
hedged risk in Revenues in the Consolidated Statement of Operations during the
period of change. For cash flow hedges (i.e. hedging the exposure to variability
in expected future cash flows that is attributable to a particular risk), we
initially report the effective portion of the gain or loss on the derivative
instrument as a component of Other Accumulated Comprehensive Income and
subsequently reclassify it to Revenues in the Consolidated Statement of
Operations when the forecasted transaction affects earnings. The remaining gain
or loss on the derivative instrument in excess of the cumulative change in the
present value of future cash flows of the hedged item, if any, is recognized
currently in Revenues during the period of change. For a hedge of a net
investment in a foreign currency, we include the effective portion of the gain
or loss in Other Accumulated Comprehensive Income as part of the cumulative
translation adjustment. We recognize any ineffective portion of the gain or loss
in Revenues immediately during the period of change.
We recognize all derivative instruments at fair value in our Consolidated
Balance Sheets as either "Risk Management Assets" or "Risk Management
Liabilities." We do not consider contracts that have been elected normal
purchase or normal sale under SFAS 133 to be derivatives. Unrealized and
realized gains and losses on all derivative instruments are ultimately included
in Revenues in the Consolidated Statement of Operations on a net basis, with the
exception of physically settled Resale Gas Contracts for the purchase of natural
gas. The unrealized and realized gains and losses on these Resale Gas Contracts
are presented as Purchased Gas for Resale in the Consolidated Statement of
Operations.
Fair Value Hedging Strategies
- -----------------------------
We enter into natural gas forward and swap transactions to hedge natural gas
inventory. The purpose of the hedging activity is to protect the natural gas
inventory against changes in fair value due to changes in the spot gas prices.
During the year ended December 31, 2003, we recognized a pre-tax loss of
approximately $3.4 million within revenues related to hedge ineffectiveness and
changes in time value excluded from the assessment of hedge ineffectiveness.
We enter into interest rate forward and swap transactions for interest rate risk
exposure management purposes. The interest rate forward and swap transactions
effectively modifies our exposure to interest risk by converting a portion of
our fixed-rate debt to a floating rate. We do not hedge all interest rate
exposure.
Cash Flow Hedging Strategies
- ----------------------------
We enter into forward contracts to protect against the reduction in value of
forecasted cash flows resulting from transactions denominated in foreign
currencies. When the dollar strengthens significantly against the foreign
currencies, the decline in value of future foreign currency revenue is offset by
gains in the value of the forward contracts designated as cash flow hedges.
Conversely, when the dollar weakens, the increase in the value of future foreign
currency cash flows is offset by losses in the value of forward contracts. We do
not hedge all foreign currency exposure.
We enter into interest rate forward and swap transactions in order to manage
interest rate risk exposure. These transactions effectively modify our exposure
to interest risk by converting a portion of our floating-rate debt to a fixed
rate. We do not hedge all interest rate exposure.
We enter into forward and swap transactions for the purchase and sale of
electricity and natural gas to manage the variable price risk related to the
forecasted purchase and sale of electricity. We closely monitor the potential
impacts of commodity price changes and, where appropriate, enter into contracts
to protect margins for a portion of future sales and generation revenues. We do
not hedge all variable price risk exposure related to the forecasted purchase
and sale of electricity.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on
our Consolidated Balance Sheets at December 31, 2003 are:
Portion Expected to
Accumulated Be Reclassified to
Hedging Hedging Other Comprehensive Earnings during
Assets Liabilities Income (Loss) After Tax the Next 12 Months
------ ----------- ----------------------- ------------------
(in millions)
Power and Gas $21 $(121) $(65) $(58)
Interest Rate - (7) (9)* (8)
Foreign Currency - (30) (20) (20)
----- -----
$(94) $(86)
===== =====
* Includes $6 million loss recorded in an equity investment.
The net losses from cash flow hedges in Accumulated Other Comprehensive Income
(Loss) at December 31, 2003 are expected to be reclassified to net income in the
next twelve months as the items being hedged settle. The actual amounts
reclassified from AOCI 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.
The following table represents the activity in Accumulated Other Comprehensive
Income (Loss) for derivative contracts that qualify as cash flow hedges at
December 31, 2003: (in millions)
Beginning Balance, January 1, 2003 $(16)
Changes in fair value (79)
Reclasses from AOCI to net gain 1
-----
Ending Balance, December 31, 2003 $(94)
=====
Hedge of Net Investment in Foreign Operations
- ---------------------------------------------
In 2001 and 2002, we used foreign denominated fixed-rate debt to protect the
value of our investments in foreign subsidiaries in the U.K. Realized gains and
losses from these hedges are not included in the income statement, but are shown
in the cumulative translation adjustment account included in Other Accumulated
Comprehensive Income.
During 2002, we recognized $64 million of net losses, included in the cumulative
translation adjustment, related to the foreign denominated fixed-rate debt.
FINANCIAL INSTRUMENTS
- ---------------------
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 at December
31, 2003 and 2002 are summarized in the following tables.
2003 2002
------------------------------ ----------------------------------
Book Value Fair Value Book Value Fair Value
---------- ---------- ---------- ----------
(in millions) (in millions)
Long-term Debt $14,101 $14,621 $10,190 $10,535
Cumulative Preferred
Stocks of Subsidiaries
Subject to Mandatory
Redemption* 76 76 84 77
Trust Preferred Securities - - 321 324
* See Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
for the effect of SFAS 150 in 2003.
Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value
- --------------------------------------------------------------------------
The trust investments which are classified as available for sale for
decommissioning and SNF disposal, reported in "Spent Nuclear Fuel and
Decommissioning Trusts" and "Assets Held for Sale" on our Consolidated Balance
Sheets, are recorded at market value in accordance with SFAS 115 "Accounting for
Certain Investments in Debt and Equity Securities." At December 31, 2003 and
2002, the fair values of the trust investments were $1,107 million and $969
million, respectively, and had a cost basis of $995 million and $909 million,
respectively. The change in market value in 2003, 2002, and 2001 was a net
unrealized holding gain of $53 million and a net unrealized holding loss of $33
million and $11 million, respectively.
15. INCOME TAXES
- -----------------
The details of our consolidated income taxes before discontinued operations,
extraordinary items, and cumulative effect as reported are as follows:
Year Ended December 31,
-----------------------------------------------
2003 2002 2001
---- ---- ----
(in millions)
Federal:
Current $297 $307 $411
Deferred 34 (60) 54
----- ----- -----
Total 331 247 465
----- ----- -----
State and Local:
Current 19 32 61
Deferred 1 28 34
----- ----- -----
Total 20 60 95
----- ----- -----
International:
Current 7 8 (7)
Deferred - - -
----- ----- -----
Total 7 8 (7)
----- ----- -----
Total Income Tax as Reported Before
Discontinued Operations, Extraordinary Items and
Cumulative Effect $358 $315 $553
===== ===== =====
The following is a reconciliation of our consolidated 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,
---------------------------------------------
2003 2002 2001
--------- --------- --------
(in millions)
Net Income (Loss) $110 $(519) $ 971
Discontinued Operations (net of income tax of $312 million,
$174 million and $14 million in 2003, 2002 and 2001,
respectively) 605 654 (41)
Extraordinary Items (net of income tax of $20 million in
2001) - - 48
Cumulative Effect of Accounting Change
(net of income tax of $138 million in 2003) (193) 350 (18)
Preferred Stock Dividends 9 11 10
----- ------ -------
Income Before Preferred Stock Dividends of Subsidiaries 531 496 970
Income Taxes Before Discontinued Operations,
Extraordinary Items and Cumulative Effect 358 315 553
----- ------ -------
Pre-Tax Income $889 $ 811 $1,523
===== ====== =======
Income Taxes on Pre-Tax Income at Statutory Rate (35%) $311 $ 284 $ 533
Increase (Decrease) in Income Taxes Resulting from the
Following Items:
Depreciation 40 32 48
Asset Impairments and Investment Value Losses 23 4 -
Investment Tax Credits (net) (33) (35) (37)
Tax Effects of International Operations 8 27 (22)
Energy Production Credits (15) (14) -
State Income Taxes 13 39 62
Other 11 (22) (31)
----- ------ -------
Total Income Taxes as Reported Before
Discontinued Operations, Extraordinary Items and
Cumulative Effect $358 $ 315 $ 553
===== ====== =======
Effective Income Tax Rate 40.3% 38.8% 36.3%
The following table shows our elements of the net deferred tax liability and the
significant temporary differences.
As of December 31,
--------------------------
2003 2002
----------- --------
(in millions)
Deferred Tax Assets $ 3,354 $ 2,604
Deferred Tax Liabilities (7,311) (6,520)
-------- ---------
Net Deferred Tax Liabilities $(3,957) $(3,916)
======== ========
Property Related Temporary Differences $(2,836) $(3,195)
Amounts Due From Customers For Future Federal
Income Taxes (389) (360)
Deferred State Income Taxes (416) (422)
Transition Regulatory Assets (254) (234)
Regulatory Assets Designated for Securitization (281) (310)
Deferred Income Taxes on Other Comprehensive Loss 306 326
All Other (net) (87) 279
-------- --------
Net Deferred Tax Liabilities $(3,957) $(3,916)
======== ========
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.
We join in the filing of a consolidated federal income tax return with our
affiliated companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is in accordance
with SEC rules under the 1935 Act. These rules permit the allocation of the
benefit of current tax losses to the System companies giving rise to them in
determining their current tax expense. The tax loss of the System parent
company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.
With the exception of the loss of the parent company, the method of allocation
approximates a separate return result for each company in the consolidated
group.
16. 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,
------------------------------------------------------------
2003 2002 2001
-------------- ------------- -----------
(in millions)
Lease Payments on Operating Leases $330 $346 $292
Amortization of Capital Leases 64 65 82
Interest on Capital Leases 9 14 22
----- ----- -----
Total Lease Rental Costs $403 $425 $396
===== ===== =====
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
----------------------
2003 2002
--------- ---------
(in millions)
Property, Plant and Equipment Under Capital Leases
Production $ 37 $ 40
Distribution 15 15
Other 470 687
----- -----
Total Property, Plant and Equipment 522 742
Accumulated Amortization 218 299
----- -----
Net Property, Plant and Equipment Under Capital Leases $304 $443
===== =====
Obligations Under Capital Leases:
Noncurrent Liability $131 $170
Liability Due Within One Year 51 58
----- -----
Total Obligations under Capital Leases $182 $228
===== =====
Future minimum lease payments consisted of the following at December 31, 2003:
Noncancelable
Capital Leases Operating Leases
-------------- ----------------
(in millions)
2004 $ 63 $ 291
2005 43 255
2006 34 237
2007 31 227
2008 18 214
Later Years 31 2,331
----- -------
Total Future Minimum Lease Payments 220 $3,555
=======
Less Estimated Interest Element 38
-----
Estimated Present Value of Future
Minimum Lease Payments $182
=====
Power Generation Facility
- -------------------------
We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Construction of the Facility was begun by Katco Funding, Limited Partnership
(Katco), an unrelated unconsolidated special purpose entity. Katco assigned its
interest in the Facility to Juniper in June 2003.
Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after
construction is completed.
At December 31, 2002, we would have reported the Facility and related
obligations as an operating lease upon achieving commercial operation (COD). In
the fourth quarter of 2003, we chose to not seek funding from Juniper for
budgeted and approved pipeline construction costs related to the Facility. In
order to continue reporting the Facility as an off-balance sheet financing, we
were required to seek funding of our construction costs from Juniper. As a
result, we recorded $496 million of construction work in progress (CWIP) and the
related financing liability for the debt and equity as of December 31, 2003. At
December 31, 2003, the lease of the Facility is reported as an owned asset under
a lease financing transaction. Since the debt obligations of the Facility are
recorded on our financial statements, the obligations under the lease agreement
are excluded from the above table of future minimum lease payments.
We are the construction agent for Juniper. We expect to achieve COD in the
spring of 2004, at which time the obligation to make payments under the lease
agreement will begin to accrue and we will sublease the Facility to The Dow
Chemical Company (Dow). If COD does not occur on or before March 14, 2004,
Juniper has the right to terminate the project. In the event the project is
terminated before COD, we have the option to either purchase the Facility for
100% of Juniper's acquisition cost (in general, the outstanding debt and equity
associated with the Facility) or terminate the project and make a payment to
Juniper for 89.9% of project costs (in general, the acquisition cost less
certain financing costs).
The initial term of the lease agreement between Juniper and AEP commences on COD
and continues for five years. The lease contains extension options, and if all
extension options are exercised, the total term of the lease will be 30 years.
AEP's lease payments to Juniper during the initial term and each extended term
are sufficient for Juniper to make required debt payments under Juniper's debt
financing associated with the Facility and provide a return on equity to the
investors in Juniper. We have the right to purchase the Facility for the
acquisition cost during the last month of the initial term or on any monthly
rent payment date during any extended term. In addition, we may purchase the
Facility from Juniper for the acquisition cost at any time during the initial
term if we have arranged a sale of the Facility to an unaffiliated third party.
A purchase of the Facility from Juniper by AEP should not alter Dow's rights to
lease the Facility or our contract to purchase energy from Dow. If the lease
were renewed for up to a 30-year lease term, we may further renew the lease at
fair market value subject to Juniper's approval, purchase the Facility at its
acquisition cost, or sell the Facility, on behalf of Juniper, to an independent
third party. If the Facility is sold and the proceeds from the sale are
insufficient to pay all of Juniper's acquisition costs, we may be required to
make a payment (not to exceed $396 million) to Juniper of the excess of
Juniper's acquisition costs over the proceeds from the sale, provided that we
would not be required to make any payment if we have made the additional rental
prepayment described below. We have guaranteed the performance of our
subsidiaries to Juniper during the lease term. Because we now report the debt
related to the Facility on our balance sheet, the fair value of the liability
for our guarantee (the $396 million payment discussed above) is not separately
reported.
At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496
million, and total costs for the completed Facility are currently expected to be
approximately $525 million. For the 30-year extended lease term, the base lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently,
as market interest rates increase, the base rental payments under the lease will
also increase. Annual payments of approximately $18 million represent future
minimum payments for interest on Juniper's financing structure during the
initial term calculated using the indexed LIBOR rate (1.15% at December 31,
2003). An additional rental prepayment (up to $396 million) may be due on June
30, 2004 unless Juniper has refinanced its present debt financing on a long-term
basis. Juniper is currently planning to refinance by June 30, 2004. The Facility
is collateral for the debt obligation of Juniper. At December 31, 2003, we
reflected $396 million of the $496 million recorded obligation as long-term debt
due within one year. Our maximum required cash payment as a result of our
financing transaction with Juniper is $396 million as well as interest payments
during the lease term. Due to the treatment of the Facility as a financing of an
owned asset, the recorded liability of $496 million is greater than our maximum
possible cash payment obligation to Juniper.
Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW
of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years
under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming.
See further discussion in Notes 7 and 10.
Gavin Lease
- -----------
OPCo has entered into an agreement with JMG, an unrelated 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 commercial
paper, pollution control bonds and other bonds. JMG was formed to design,
construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the
Gavin Scrubber and leases it to OPCo. Prior to July 1, 2003, the lease was
accounted for as an operating lease. Payments under the lease agreement are
based on JMG's cost of financing (both debt and equity) and include an
amortization component plus the cost of administration. OPCo and AEP do not have
an ownership interest in JMG and do 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 on behalf of
JMG. 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 on behalf of JMG. In case of a sale at
less than the adjusted acquisition cost, OPCo must pay the difference to JMG.
On March 31, 2003, OPCo made a prepayment of $90 million under this lease
structure. AEP recognizes lease expense on a straight-line basis over the
remaining lease term, in accordance with SFAS 13 "Accounting for Leases." The
asset will be amortized over the remaining lease term, which ends in the first
quarter of 2010.
On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46. Upon
consolidation, OPCo recorded the assets and liabilities of JMG ($469.6 million).
OPCo now records the depreciation, interest and other operating expenses of JMG
and eliminates JMG's revenues against OPCo's operating lease expenses. There was
no cumulative effect of an accounting change recorded as a result of our
requirement to consolidate JMG, and there was no change in net income due to the
consolidation of JMG. Since the debt obligations of JMG are now consolidated,
the JMG lease is no longer accounted for on a consolidated basis as an operating
lease and has been excluded from the above table of future minimum lease
payments.
Rockport Lease
- --------------
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 future minimum lease payments
for each respective company are $1.4 billion.
The FASB and other accounting constituencies continue to interpret the
application of FIN 46R. As a result, we are continuing to review the application
of this new interpretation as it relates to the Rockport Plant Unit 2
transaction.
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 future minimum lease payments schedule earlier in
this note. 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. Neither AEGCo, I&M nor AEP has an ownership
interest in the Owner Trustee and do not guarantee its debt.
Railcar Lease
- -------------
In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years. We intend to renew the lease for
the full twenty years. At the end of each lease term, we may (a) renew for
another five-year term, not to exceed a total of twenty years, (b) purchase the
railcars for the purchase price amount specified in the lease, projected at the
lease inception to be the then fair market value, or (c) return the railcars and
arrange a third party sale (return-and-sale option). The lease is accounted for
as an operating lease with the future payment included in the future minimum
lease payments schedule earlier in this note. This operating lease agreement
allows us to avoid a large initial capital expenditure, and to spread our
railcar costs evenly over the expected twenty-year usage.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under
the return-and-sale option discussed above will equal at least a lessee
obligation amount specified in the lease, which declines over the term from
approximately 86% to 77% of the projected fair market value of the equipment. At
December 31, 2003, the maximum potential loss was approximately $31.5 million
($20.5 million net of tax) assuming the fair market value of the equipment is
zero at the end of the current lease term. The railcars are subleased for one
year to an unaffiliated company under an operating lease. The sublessee may
renew the lease for up to four additional one-year terms. AEP has other rail car
lease arrangements that do not utilize this type of structure.
17. FINANCING ACTIVITIES
- -------------------------
Trust Preferred Securities
- --------------------------
PSO, SWEPCo and TCC have wholly-owned business trusts that have issued trust
preferred securities. The trusts which hold mandatorily redeemable trust
preferred securities were deconsolidated effective July 1, 2003 due to the
implementation of FIN 46. Therefore, $321 million ($75 million PSO, $110 million
SWEPCo and $136 million TCC), previously reported at December 31, 2002 as
Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries, is now reported as two components on the Balance Sheet. The $10
million investment in the trust is now reported as Other within Other
Non-Current Assets while the $331 million of subordinated debentures are now
reported as Notes Payable to Trust within Long-term Debt.
The Junior Subordinated Debentures of PSO and TCC mature on April 30, 2037. In
October 2003, SWEPCo refinanced its Junior Subordinated Debentures which are now
due October 1, 2043. The following Trust Preferred Securities issued by the
wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding
at December 31, 2003 and 2002:
Amount
Units Amount in Reported Description of
Issued/ Amount in Notes Payable Prior to Underlying
Outstanding Other to Trust FIN 46 Debentures of
Business Trust Security at 12/31/03 at 12/31/03(a) at 12/31/03(b) at 12/31/02(c) Registrant
- -------------- -------- ----------- ------------- ------------- -------------- --------------
(in millions) (in millions) (in millions)
CPL Capital I 8.00%, Series A 5,450,000 $ 5 $141 $136 TCC, $141 million,
8.00%, Series A
PSO Capital I 8.00%, Series A 3,000,000 2 77 75 PSO, $77 million,
8.00%, Series A
SWEPCo Capital I 7.875%, Series A - - - 110 SWEPCo, $113 million,
7.875%, Series A
SWEPCo Capital I 5.25%, Series B 110,000 3 113 - SWEPCo, $113 million,
----------- ---- ----- ----- 5.25% five year fixed
rate period, Series B
Total 8,560,000 $10 $331 $321
========== ==== ===== =====
(a) Amounts are in Other within Other Non-Current Assets.
(b) Amounts are in Notes Payable to Trust within Long-term Debt.
(c) Amounts reported on Balance Sheet prior to FIN 46.
Each of the business trusts is treated as a non-consolidated 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.
Minority Interest in Finance Subsidiary
- ---------------------------------------
We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis
Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated
subsidiary that was capitalized with the assets of Houston Pipe Line Company and
Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas
Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of
SubOne) preferred stock, that was 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 for a managing member interest and $750 million from
Steelhead Investors LLC (Steelhead) for a non-controlling preferred member
interest. As managing member, SubOne consolidated Caddis. Steelhead is an
unconsolidated special purpose entity and had an original capital structure of
$750 million (currently approximately $525 million) of which 3% is equity from
investors with no relationship to us or any of our subsidiaries and 97% is debt
from a syndicate of banks. The $525 million invested in Caddis by Steelhead was
loaned to SubOne. The loan to SubOne is due August 2006. Net proceeds from the
proposed sale of LIG will be used to reduce the outstanding balance of the loan
from Caddis (see Note 10 for additional information on LIG and HPL).
On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis,
which included amounts previously reported as Minority Interest in Finance
Subsidiary ($759 million at December 31, 2002 and $533 million at June 30,
2003). As a result, a note payable to Caddis is reported as a component of
Long-term Debt ($527 million at December 31, 2003). Due to the prospective
application of FIN 46, we did not change the presentation of Minority Interest
in Finance Subsidiary in periods prior to July 1, 2003.
On May 9, 2003, SubOne borrowed $225 million from us and used the proceeds to
reduce the outstanding balance of the loan from Caddis, which Caddis used to
reduce the preferred interest held by Steelhead. This payment eliminated the
convertible preferred stock of AEP Gas Holding which under certain conditions
had been convertible to AEP common stock.
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,
2003, SubOne has complied with the covenants contained in the credit agreement.
In addition, the acceleration of outstanding debt in excess of $50 million would
be an event of default under the credit agreement.
SubOne has deposited $422 million in a cash reserve fund in order to comply with
certain covenants in the credit agreement. Pursuant to the terms of the credit
agreement, SubOne subsequently loaned these funds to affiliates, and we
guaranteed the repayment obligations of these affiliates. These loans must be
repaid in the event our credit ratings fall below investment grade.
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. Liquidation of Caddis could negatively impact our
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 us.
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 is making quarterly interest payments on the senior notes at an initial
annual rate of 5.75%. The interest rate can be reset through a remarketing,
which is initially scheduled for May 2005. AEP makes 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 was recorded as
a $31 million liability in Equity Unit Senior Notes offset by a charge to
Paid-in Capital in June 2002. Interest payments on the senior notes are reported
as interest expense. Accretion of the contract adjustment payment liability is
reported as interest expense.
AEP applies the treasury stock method to the equity units to calculate diluted
earnings per share. This method of calculation theoretically assumes that the
proceeds received as a result of the forward purchase contract are used to
repurchase outstanding shares.
Lines of Credit - AEP System
- ----------------------------
We use our corporate borrowing program to meet the short-term borrowing needs of
our subsidiaries. The corporate borrowing program includes a utility money pool,
which funds the utility subsidiaries, and a non-utility money pool, which funds
the majority of the non-utility subsidiaries. In addition, we also fund, as
direct borrowers, the short-term debt requirements of other subsidiaries that
are not participants in the non-utility money pool for regulatory or operational
reasons. As of December 31, 2003, we had credit facilities totaling $2.9 billion
to support our commercial paper program. At December 31, 2003, AEP had $326
million outstanding in short-term borrowings of which $282 million was
commercial paper supported by the revolving credit facilities. In addition, JMG
has commercial paper outstanding in the amount of $26 million. This commercial
paper is specifically associated with the Gavin scrubber lease identified in
Note 16 "Leases". This commercial paper does not reduce available liquidity to
AEP. The maximum amount of commercial paper outstanding during the year, which
had a weighted average interest rate during 2003 of 1.98%, was $1.5 billion
during January 2003. 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. On March 7, 2003, Standard
& Poor's Rating Services reaffirmed AEP's A-2 short-term rating for commercial
paper.
Outstanding Short-term Debt consisted of:
December 31,
------------
2003 2002
---- ----
(in millions)
Balance Outstanding:
Notes Payable $ 18 $1,322
Commercial Paper - AEP 282 1,417
Commercial Paper - JMG 26 -
----- -------
Total $326 $2,739
===== =======
Sale of Receivables - AEP Credit
- --------------------------------
AEP Credit has a sale of receivables agreement with banks and commercial paper
conduits. Under the sale of receivables agreement, 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.
We entered into this off-balance sheet transaction to allow AEP Credit to repay
its outstanding debt obligations, continue to purchase the AEP operating
companies' receivables, and accelerate its cash collections.
AEP Credit extended its sale of receivables agreement to July 25, 2003 from its
May 28, 2003 expiration date. The agreement was then renewed for an additional
364 days and now expires on July 23, 2004. This new agreement provides
commitments of $600 million to purchase receivables from AEP Credit. At December
31, 2003, $385 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. AEP
Credit maintains a retained interest in the receivables sold and this interest
is pledged as collateral for the collection of the receivables sold. The fair
value of the retained interest is based on book value due to the short-term
nature of the accounts receivable less an allowance for anticipated
uncollectible accounts.
AEP Credit purchases accounts receivable through purchase agreements with
certain registrant subsidiaries and, until the first quarter of 2002, with
non-affiliated companies. These subsidiaries include CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority
to sell accounts receivable in all of its regulatory jurisdictions, only a
portion of APCo's accounts receivable are sold to AEP Credit. 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,
-----------------------
2003 2002
---- ----
(in millions)
Proceeds from Sale of Accounts Receivable $5,221 $5,513
Accounts Receivable Retained Interest Less Uncollectible
Accounts and Amounts Pledged as Collateral 124 76
Deferred Revenue from Servicing Accounts Receivable 1 1
Loss on Sale of Accounts Receivable 7 4
Average Variable Discount Rate 1.33% 1.92%
Retained Interest if 10% Adverse Change in Uncollectible Accounts 122 74
Retained Interest if 20% Adverse Change in Uncollectible Accounts 121 72
Historical loss and delinquency amount for the AEP System's customer accounts
receivable managed portfolio:
Face Value
Year Ended December 31,
-----------------------
2003 2002
---- ----
(in millions)
Customer Accounts Receivable Retained $1,155 $1,553
Accrued Unbilled Revenues Retained 596 551
Miscellaneous Accounts Receivable Retained 83 93
Allowance for Uncollectible Accounts Retained (124) (108)
------- -------
Total Net Balance Sheet Accounts Receivable 1,710 2,089
Customer Accounts Receivable Securitized (Affiliate) 385 454
------- ------
Total Accounts Receivable Managed $2,095 $2,543
======= =======
Net Uncollectible Accounts Written Off $ 39 $ 48
======= =======
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, 2003, delinquent customer accounts receivable for the electric
utility affiliates that AEP Credit currently factors was $30 million.
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION
- ----------------------------------------------
Our unaudited quarterly financial information is as follows:
2003 Quarterly Periods Ended
----------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(In Millions - Except Per Share Amounts)
- ----------------------------------------
Revenues $3,834 $3,451 $3,940 $3,320
Operating Income (Loss) 630 393 735 (126)
Income (Loss) Before Discontinued Operations,
Extraordinary Items and Cumulative Effect 294 185 298 (255)
Net Income (Loss) 440 175 257 (762)
Earnings (Loss) per Share Before Discontinued
Operations, Extraordinary Items and Cumulative Effect*
0.83 0.47 0.75 (0.65)
Earnings (Loss) per Share** 1.24 0.44 0.65 (1.93)
2002 Quarterly Periods Ended
----------------------------
March 31 June 30 September 30 December 31
--------- ------- ------------ -----------
(In Millions - Except Per Share Amounts)
- ----------------------------------------
Revenues $2,802 $3,395 $3,639 $3,472
Operating Income 420 433 781 170
Income (Loss) Before Discontinued Operations,
Extraordinary Items and Cumulative Effect 134 167 385 (201)
Net Income (Loss) (169) 62 425 (837)
Earnings (Loss) per Share Before Discontinued
Operations, Extraordinary Items and Cumulative
Effect*** 0.42 0.51 1.14 (0.59)
Earnings (Loss) per Share**** (0.53) 0.19 1.25 (2.47)
* Amounts for 2003 do not add to $1.35 earnings per share before Discontinued
Operations, Extraordinary Loss and Cumulative Effect due to rounding and
the dilutive effect of shares issued in 2003.
** Amounts for 2003 do not add to $0.29 earnings per share due to rounding and
the dilutive effect of shares issued in 2003.
*** Amounts for 2002 do not add to $1.46 earnings per share before Discontinued
Operations, Extraordinary Loss and Cumulative Effect due to rounding.
**** Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.
Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative
Effect for the fourth quarter 2003 ($255 million loss) and 2002 ($201 million
loss) were significantly lower than the previous three quarters due to asset
impairments, investment value losses and other related charges. These pre-tax
writedowns ($650 million in the fourth quarter 2003 and $593 million in the
fourth quarter 2002) were made to reflect impairments and discontinued
operations as discussed in Note 10.
19. SUBSEQUENT EVENTS (UNAUDITED)
- ----------------------------------
After December 31, 2003, we entered into separate agreements to dispose of the
following investments:
Investment Sales Price Date of Agreement
- ---------- ----------- -----------------
(in millions)
Oklaunion Power Station $42.8 January 30, 2004
LIG Pipeline and its subsidiaries $76.2 February 13, 2004
STP $332.6 February 27, 2004
We anticipate these sales to be completed during 2004 and that the impact on
results of operations will not be significant.
The Nanyang General Light (Pushan) investment was sold for $60.7 million on
March 2, 2004. This sale had no significant impact on our results of operations.
On March 10, 2004, we entered into an agreement to sell four domestic
Independent Power Producer (IPP) investments for a sales price of $156 million.
We anticipate this sale to be completed during 2004 and to result in a pre-tax
gain of approximately $100 million.
MANAGEMENT'S RESPONSIBILITY
- ---------------------------
The management of American Electric Power Company, Inc. (the Company) 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 previous page.
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 subsidiary companies as of December 31, 2003
and 2002, 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, 2003. 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 subsidiary companies as of December 31, 2003 and 2002,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1,
2002.
As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities" effective January 1, 2003.
As discussed in Note 2 to the consolidated financial statements, the Company
adopted FIN 46, "Consolidation of Variable Interest Entities" effective July 1,
2003.
/s/ Deloitte & Touche LLP
Columbus, Ohio
March 5, 2004