2002 Annual Reports
American Electric Power Company, Inc.
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Audited Financial Statements and
Management's Discussion and Analysis
Contents
Page
Glossary of Terms i
Forward Looking Information iv
AEP Common Stock and Dividend Information v
American Electric Power Company, Inc. and Subsidiary Companies
Selected Consolidated Financial Data A-1
Management's Discussion and Analysis of Results of Operations A-2
Consolidated Statements of Operations A-12
Consolidated Balance Sheets A-13
Consolidated Statements of Cash Flows A-15
Consolidated Statements of Common Shareholders' Equity and
Comprehensive Income A-16
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-17
Schedule of Consolidated Long-term Debt of Subsidiaries A-18
Index to Combined Notes to Consolidated Financial Statements A-19
Independent Auditors' Report A-20
Management's Responsibility A-21
AEP Generating Company
Selected Financial Data B-1
Management's Narrative Analysis of Results of Operations B-2
Statements of Income and Statements of Retained Earnings B-3
Balance Sheets B-4
Statements of Cash Flows B-6
Statements of Capitalization B-7
Index to Combined Notes to Financial Statements B-8
Independent Auditors' Report B-9
AEP Texas Central Company and Subsidiaries
Selected Consolidated Financial Data C-1
Management's Discussion and Analysis of Results of Operations C-2
Consolidated Statements of Income and Consolidated Statements of
Comprehensive Income C-6
Consolidated Statements of Retained Earnings C-7
Consolidated Balance Sheets C-8
Consolidated Statements of Cash Flows C-10
Consolidated Statements of Capitalization C-11
Schedule of Long-term Debt C-12
Index to Combined Notes to Consolidated Financial Statements C-13
Independent Auditors' Report C-14
AEP Texas North Company
Selected Financial Data D-1
Management's Narrative Analysis of Results of Operations D-2
Statements of Operations and Statements of Comprehensive Income D-6
Statements of Retained Earnings D-7
Balance Sheets D-8
Statements of Cash Flows D-10
Statements of Capitalization D-11
Schedule of Long-term Debt D-12
Index to Combined Notes to Financial Statements D-13
Independent Auditors' Report D-14
Appalachian Power Company and Subsidiaries
Selected Consolidated Financial Data E-1
Management's Discussion and Analysis of Results of Operations E-2
Consolidated Statements of Income and Consolidated Statements of
Comprehensive Income E-7
Consolidated Statements of Retained Earnings E-8
Consolidated Balance Sheets E-9
Consolidated Statements of Cash Flows E-11
Consolidated Statements of Capitalization E-12
Schedule of Long-term Debt E-13
Index to Combined Notes to Consolidated Financial Statements E-14
Independent Auditors' Report E-15
Columbus Southern Power Company and Subsidiaries
Selected Consolidated Financial Data F-1
Management's Narrative Analysis of Results of Operations F-2
Consolidated Statements of Income and
Consolidated Statements of Comprehensive Income F-6
Consolidated Statements of Retained Earnings F-7
Consolidated Balance Sheets F-8
Consolidated Statements of Cash Flows F-10
Consolidated Statements of Capitalization F-11
Schedule of Long-term Debt F-12
Index to Combined Notes to Consolidated Financial Statements F-13
Independent Auditors' Report F-14
Indiana Michigan Power Company and Subsidiaries
Selected Consolidated Financial Data G-1
Management's Discussion and Analysis of Results of Operations G-2
Consolidated Statements of Income and Consolidated Statements of
Comprehensive Income G-7
Consolidated Statements of Retained Earnings G-8
Consolidated Balance Sheets G-9
Consolidated Statements of Cash Flows G-11
Consolidated Statements of Capitalization G-12
Schedule of Long-term Debt G-13
Index to Combined Notes to Consolidated Financial Statements G-14
Independent Auditors' Report G-15
Kentucky Power Company
Selected Financial Data H-1
Management's Narrative Analysis of Results of Operations H-2
Statements of Income, Statements of Comprehensive Income
and Statements of Retained Earnings H-6
Balance Sheets H-7
Statements of Cash Flows H-9
Statements of Capitalization H-10
Schedule of Long-term Debt H-11
Index to Combined Notes to Financial Statements H-12
Independent Auditors' Report H-13
Ohio Power Company
Selected Financial Data I-1
Management's Discussion and Analysis of Results of Operations I-2
Statements of Income and Statements of Comprehensive Income I-7
Statements of Retained Earnings I-8
Balance Sheets I-9
Statements of Cash Flows I-11
Statements of Capitalization I-12
Schedule of Long-term Debt I-13
Index to Combined Notes to Financial Statements I-14
Independent Auditors' Report I-15
Public Service Company of Oklahoma and Subsidiary
Selected Consolidated Financial Data J-1
Management's Narrative Analysis of Results of Operations J-2
Consolidated Statements of Income and
Consolidated Statements of Comprehensive Income J-5
Consolidated Statements of Retained Earnings J-6
Consolidated Balance Sheets J-7
Consolidated Statements of Cash Flows J-9
Consolidated Statements of Capitalization J-10
Schedule of Long-term Debt J-11
Index to Combined Notes to Consolidated Financial Statements J-12
Independent Auditors' Report J-13
Southwestern Electric Power Company and Subsidiaries
Selected Consolidated Financial Data K-1
Management's Discussion and Analysis of Results of Operations K-2
Consolidated Statements of Income and
Consolidated Statements of Comprehensive Income K-6
Consolidated Statements of Retained Earnings K-7
Consolidated Balance Sheets K-8
Consolidated Statements of Cash Flows K-10
Consolidated Statements of Capitalization K-11
Schedule of Long-term Debt K-12
Index to Combined Notes to Consolidated Financial Statements K-13
Independent Auditors' Report K-14
Combined Notes to Financial Statements L-1
Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters M-1
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
Term Meaning
2004 True-up Proceeding............A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount
of stranded costs and the recovery of such costs.
AEGCo..............................AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................American Electric Power Company, Inc.
AEP Consolidated...................AEP and its majority owned consolidated subsidiaries.
AEP Credit.........................AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East companies.................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR...............................AEP Resources, Inc.
AEP System or the System...........The American Electric Power System, an integrated electric utility system, owned and operated
by AEP's electric utility subsidiaries.
AEPSC..............................American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool.....................AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West companies.................PSO, SWEPCo, TCC and TNC.
AFUDC..............................Allowance for funds used during construction, a noncash nonoperating income item that is
capitalized and recovered through depreciation over the service life of domestic
regulated electric utility plant.
Alliance RTO.......................Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
utilities (the FERC overturned earlier approvals of this RTO in December 2001).
Amos Plant.........................John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo...............................Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................Arkansas Public Service Commission.
Buckeye............................Buckeye Power, Inc., an unaffiliated corporation.
CLECO..............................Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI...............................Corporate owned life insurance program.
Cook Plant.........................The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................Central Power and Light Company [legal name changed to AEP Texas Central
Company (TCC) effective December 2002]. See TCC.
CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal
name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Energy.........................CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International..................CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court.................The United States Court of Appeals for the District of Columbia Circuit.
DHMV...............................Dolet Hills Mining Venture.
DOE................................United States Department of Energy.
ECOM...............................Excess Cost Over Market.
ENEC...............................Expanded Net Energy Costs.
EITF...............................The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT..............................The Electric Reliability Council of Texas.
EWGs...............................Exempt Wholesale Generators.
FASB...............................Financial Accounting Standards Board.
Federal EPA........................United States Environmental Protection Agency.
FERC...............................Federal Energy Regulatory Commission.
FMB ...............................First Mortgage Bond.
FUCOs..............................Foreign Utility Companies.
GAAP...............................Generally Accepted Accounting Principles.
I&M................................Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR................................Interchange Cost Reconstruction.
IPC................................Installment Purchase Contract.
IRS................................Internal Revenue Service.
IURC...............................Indiana Utility Regulatory Commission.
ISO................................Independent System Operator.
Joint Stipulation..................Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo...............................Kentucky Power Company, an AEP electric utility subsidiary.
KPSC...............................Kentucky Public Service Commission.
KWH................................Kilowatthour.
LIG................................Louisiana Intrastate Gas.
Michigan Legislation...............The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO...............................Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR................................Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool.........................AEP System's Money Pool.
MPSC...............................Michigan Public Service Commission.
MTM................................Mark-to-Market.
MTN................................Medium Term Notes.
MW.................................Megawatt.
MWH................................Megawatthour.
NEIL...............................Nuclear Electric Insurance Limited.
NOx................................Nitrogen oxide.
NOx Rule...........................A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including
seven of the states in which AEP companies operate.
NP.................................Notes Payable.
NRC................................Nuclear Regulatory Commission.
Ohio Act...........................The Ohio Electric Restructuring Act of 1999.
Ohio EPA...........................Ohio Environmental Protection Agency.
OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary.
OVEC...............................Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a
44.2% equity interest.
PCBs...............................Polychlorinated Biphenyls.
PJM................................Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP.............................. Potentially Responsible Party.
PSO................................Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO...............................The Public Utilities Commission of Ohio.
PUCT...............................The Public Utility Commission of Texas.
PUHCA..............................Public Utility Holding Company Act of 1935, as amended.
PURPA..............................The Public Utility Regulatory Policies Act of 1978.
RCRA...............................Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
REP................................Retail Electric Provider.
Rockport Plant.....................A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................Regional Transmission Organization.
SEC................................Securities and Exchange Commission.
SFAS...............................Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation.
---------------------------------------------------------
SFAS 101...........................Statement of Financial Accounting Standards No. 101,
Accounting for the Discontinuance of Application of Statement 71.
----------------------------------------------------------------
SFAS 133...........................Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
------------------------------------------------------------
SNF................................Spent Nuclear Fuel.
SPP................................Southwest Power Pool.
STP................................South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC.............................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
Power and Light Company (CPL)].
Texas Appeals Court................The Third District of Texas Court of Appeals.
Texas Legislation..................Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
Utilities Company (WTU)].
Travis District Court..............State District Court of Travis County, Texas.
TVA ...............................Tennessee Valley Authority.
U.K................................The United Kingdom.
UN.................................Unsecured Note.
VaR................................Value at Risk, a method to quantify risk exposure.
Virginia SCC.......................Virginia State Corporation Commission.
WV.................................West Virginia.
WVPSC..............................Public Service Commission of West Virginia.
WPCo...............................Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................West Texas Utilities Company [legal name changed to AEP Texas North Company (TNC) effective
December 2002]. See TNC.
Yorkshire..........................Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP and
New Century Energies until April 2001.
Zimmer Plant.......................William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
FORWARD LOOKING INFORMATION
These reports made by AEP and its registrant subsidiaries contain
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and its registrant
subsidiaries believe that their expectations are based on reasonable
assumptions, any such statements may be influenced by factors that could
cause actual outcomes and results to be materially different from those
projected. Among the factors that could cause actual results to differ
materially from those in the forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our service
territories.
o The ability to recover stranded costs in connection with
possible/proposed deregulation.
o New legislation and government regulation.
o Oversight and/or investigation of the energy sector or its
participants.
o The ability of AEP to successfully control its costs.
o The success of acquiring new business ventures and disposing of
existing investments that no longer match our corporate profile.
o International and country-specific developments affecting AEP's foreign
investments including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in AEP's service territory and
changes in market demand and demographic patterns.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates.
o Liquidity in the banking, capital and wholesale power markets.
o Actions of rating agencies.
o Changes in technology, including the increased use of distributed
generation within our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
AEP Common Stock and Dividend Information
The quarterly high and low sales prices and the quarter-end closing price for
AEP common stock and the cash dividends paid per share are shown in the
following table:
Quarter-end
Quarter Ended High Low Closing Price Dividend
- ------------- ------ ------- ------------- --------
March 2002 $47.08 $39.70 $46.09 $0.60
June 2002 48.80 39.00 40.02 0.60
September 2002 40.37 22.74 28.51 0.60
December 2002 30.55 15.10 27.33 0.60
March 2001 $48.10 $39.25 $47.00 $0.60
June 2001 51.20 45.10 46.17 0.60
September 2001 48.90 41.50 43.23 0.60
December 2001 46.95 39.70 43.53 0.60
AEP common stock is traded principally on the New York Stock Exchange. At
December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003
management recommended that the Company reduce dividends by approximately 40%
after payment of the March 2003 dividend which was approved by the Company's
Board of Directors at the current level of $0.60 per share.
AMERICAN ELECTRIC POWER COMPANY, INC.
AND SUBSIDIARY COMPANIES
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data
Year Ended December 31, 2002 2001 2000 1999 1998
- ----------------------- ---- ---- ---- ---- ----
OPERATIONS STATEMENTS DATA (in millions):
Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080
Operating Income 1,263 2,182 1,774 2,061 2,046
Income Before Discontinued Operations, Extraordinary
Items and Cumulative Effect 21 917 180 869 859
Discontinued Operations Income (Loss) (190) 86 122 117 116
Extraordinary Losses - (50) (35) (14) -
Cumulative Effect of
Accounting Change Gain (Loss) (350) 18 - - -
Net Income (Loss) (519) 971 267 972 975
December 31, 2002 2001 2000 1999 1998
- ------------ ---- ---- ---- ---- ----
BALANCE SHEET DATA (in millions):
Property, Plant and Equipment $37,857 $37,414 $34,895 $33,930 $32,400
Accumulated Depreciation
and Amortization 16,173 15,310 14,899 14,266 13,374
------- ------- ------- ------- -------
Net Property,
Plant and Equipment $21,684 $22,104 $19,996 $19,664 $19,026
======= ======= ======= ======= =======
Total Assets $34,741 $39,297 $46,633 $35,296 $33,418
Common Shareholders' Equity 7,064 8,229 8,054 8,673 8,452
Cumulative Preferred Stocks
of Subsidiaries* 145 156 161 182 350
Trust Preferred Securities 321 321 334 335 335
Long-term Debt* 10,496 9,505 8,980 9,471 9,215
Obligations Under Capital Leases* 228 451 614 610 539
Year Ended December 31, 2002 2001 2000 1999 1998
- ----------------------- ---- ---- ---- ---- ----
COMMON STOCK DATA:
Earnings per Common Share:
Before Discontinued Operations, Extraordinary
Items and Cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70
Discontinued Operations (0.57) 0.26 0.38 0.36 0.36
Extraordinary Losses - (0.16) (0.11) (0.04) -
Cumulative Effect of
Accounting Change (1.06) 0.06 - - -
------- ------ ------ ------ -----
Earnings (Loss) Per Share $ (1.57) $ 3.01 $ 0.83 $ 3.03 $3.06
======= ====== ====== ====== =====
Average Number of Shares
Outstanding (in millions) 332 322 322 321 318
Market Price Range:
High $ 48.80 $51.20 $48-15/16 $48-3/16 $53-5/16
Low 15.10 39.25 25-15/16 30-9/16 42-1/16
Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16
Cash Dividends on Common** $ 2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4%
Book Value per Share $20.85 $25.54 $25.01 $26.96 $26.46
*Including portion due within one year. Long-term Debt includes Equity Unit Senior Notes.
**Based on AEP historical dividend rate. See "Common Stock and Dividend
Information" (on page V) regarding the potential reduction of future dividends.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations
American Electric Power Company, Inc. (AEP or the Company) is one of the largest
investor owned electric public utility holding companies in the U.S. We provide
generation, transmission and distribution service to almost five million retail
customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our
electric utility operating companies.
We have a vast portfolio of assets including:
o 38,000 megawatts of generating capacity, the largest complement
of generation in the U.S., the majority of which has a
significant cost advantage in our market areas
o 4,000 megawatts of generating capacity in the U.K., a country which is
currently experiencing excess generation capacity
o 38,000 miles of transmission lines, the backbone of the electric
interconnection grid in the Eastern U.S.
o 186,000 miles of distribution lines that support delivery of
electricity to our customers' premises
o Substantial coal transportation assets (7,000 railcars, 1,800 barges,
37 tug boats and two coal handling terminals with 20 million tons of
annual capacity)
o 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of
gas storage facilities
Business Strategy
We plan to focus on utility operations in the U.S. We continue to participate in
wholesale electricity and natural gas markets. Weakness in these markets after
the collapse of Enron and other companies caused us to re-examine and realign
our strategy to direct our attention to our utility markets. We have reduced
trading to focus predominantly in markets where we have assets. We plan to
obtain maximum value for our assets by selling excess output and procuring
economical energy using commercial expertise gained from our extensive
experience in the wholesale business.
Through our utility operations focus, we intend to be the energy and low cost
generation provider of choice. We have ample generation to meet our customers'
needs. We have a cost advantage resulting from AEP's long tradition of
designing, building and operating efficient power plants and delivery networks.
Our customers continue to show top quartile level of satisfaction. We provide
safe and reliable sources of energy.
Our business provides a vital requirement of our economy and affords an
opportunity for a fair return to our shareholders. Our business provides the
opportunity for a predictable stream of cash flows and earnings, allowing us to
pay a competitive dividend to investors.
We are addressing many challenges in our unregulated business. We have already
substantially reduced our trading activities. We have written down the value of
several investments to reflect deterioration in market conditions. We are
evaluating our portfolio and plan to sell assets that are no longer core to our
business strategy. We are also in discussion with our regulators to determine if
the legal separation of certain operating company subsidiaries into regulated
and unregulated segments can be avoided. We believe that the expected benefits
from legal separation are no longer compelling. Transition rules for Michigan
and Virginia do not require legal separation. Deregulation is no longer an
expectation in the foreseeable future in the other states where we operate.
Our strategy for the core business of utility operations is to:
o Maintain moderate but steady earnings growth
o Maximize value of transmission assets and protect our revenue stream
in an RTO membership environment
o Continue process improvement to maintain distribution service quality
while, at the same time, further enhancing financial performance
o Optimize generation assets through increased availability and sale of
excess capacity
o Manage the regulatory process to maximize retention of earnings
improvement while providing fair and reasonable rates to our
customers
We remain very focused on credit quality and liquidity as discussed in greater
detail later in this report.
We are committed to continually evaluating the need to reallocate resources to
areas with greater potential, to match investments with our strategy and to pare
investments that do not produce sufficient return and sustainable shareholder
value. Any investment dispositions could affect future results of operations,
cash flows and possibly financial condition.
2002 Overview
2002 was a year of rapid and dramatic change for the energy industry, including
AEP, as the wholesale energy market quickly shrank and many of its participants
exited or significantly limited future trading activity. Investors lost
confidence in corporate America and the economy stalled. Investors' demand for
stability, predictable cash flows, earnings, and financial strength have
replaced their demand for rapid growth.
Our wholesale business did not perform well. We had significant losses in
options trading in the first half of the year and new investments performed well
below our expectations.
We focused on financial strength by:
o Issuing approximately $1 billion in common stock and equity units
o Retiring debt of approximately $3 billion through the sale of two f
oreign retail utility companies in the U.K. (SEEBOARD) and
Australia (CitiPower)
o Establishing a cash liquidity reserve of $1 billion at year-end
See Financing Activity in Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters in section M for an overview of
all changes to capital structure.
We also focused on:
o Implementing an enterprise-wide risk management system
o Completing a cost reduction initiative which we expect to result in
sustainable net annual savings of more than $200 million beginning
in 2003
o Eliminating or reducing future capital requirements associated with
non-core assets
We have redirected our business strategy by:
o Scaling back trading activities to focus principally on supporting
our core assets
o Selling our Texas retail business o Proposing the sale of a significant
portion of the Texas unregulated generation assets
Outlook for 2003
We remain focused on the fundamental earnings power of our utility operations,
and we are committed to strengthening our balance sheet. Our strategy for
achieving these goals is well planned:
o First, we will continue to identify opportunities to reduce our
operations and maintenance expense.
o Second, we will find opportunities to reduce capital expenditures.
o Third, management recommended a 40% reduction in the common stock
dividend beginning in the second quarter to a quarterly rate of $0.35
per share. This will result in annual cash savings of approximately
$340 million and should improve our retained earnings as well as create
free cash flow to improve liquidity and pay-down outstanding debt.
o Fourth, we plan to evaluate and, where appropriate, dispose of non-core
assets. Proceeds from these sales will be used to reduce debt.
o Fifth, we will continue to evaluate the potential for issuing
additional equity to further strengthen our balance sheet and maintain
credit quality.
We remain committed to being a low cost provider of electricity, to serving our
customers with excellence and to providing an attractive return to investors. We
will therefore focus on producing the best possible results from our utility
operations enhanced by a commercial group that ensures maximum value from our
assets.
Although we aim for excellent results from operations there are challenges and
certain risks. We discuss these matters in detail in the Notes to Financial
Statements and in Management's Discussion and Analysis of Financial Condition,
Accounting Policies and Other Matters. We will work diligently to resolve these
matters by finding workable solutions that balance the interests of our
customers, our employees and our investors.
Results of Operations
In 2002, AEP's principal operating business segments and their major activities
were:
o Wholesale:
o Generation of electricity for sale to retail and wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas, coal and other
commodities
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
o Energy Delivery
o Domestic electricity trans-mission
o Domestic electricity distri-bution
o Other Investments
o Energy Services
Net Income
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001.
The Company recognized impairments on under-performing assets and recorded
losses in value of $854 million (net of tax) (see Note 13). The losses in the
fourth quarter 2002 were generally caused by the extended decline in domestic
and international wholesale energy markets and in telecommunications. In 2002,
the Company's Net Loss was $519 million or a loss of $1.57 per share including
the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss
for transitional goodwill impairment related to SEEBOARD and CitiPower that
resulted from the adoption of SFAS 142 (see Note 3).
Net Income increased in 2001 to $971 million or $3.01 per share from $267
million or $0.83 per share in 2000. The increase of $704 million or $2.18 per
share was due to the growth of AEP's wholesale marketing business, increased
revenues and the controlling of our operating and maintenance costs in the
energy delivery business, and declining capital costs. The effect of 2000
charges for a disallowance of COLI-related tax deductions, expenses of the
merger with CSW, write-offs related to non-regulated investments and restart
costs of the Cook Nuclear Plant were all contributing factors to the increase in
2001 earnings compared to 2000. The favorable effect on comparative Net Income
of these 2000 charges was offset in part in 2001 by losses from Enron's
bankruptcy and extraordinary losses for the effects of deregulation and a loss
on reacquired debt.
Our wholesale business has been affected by a slowing economy. Wholesale energy
margins and energy use by industrial customers declined in 2002 and 2001.
Earnings from our wholesale business, which includes generation, increased in
2001 largely as a result of the successful return to service of the Cook Plant
in June 2000 and by acquisitions of HPL and MEMCO.
Our energy delivery business, which consists of domestic electricity
transmission and distribution services, contributed to the increase in earnings
by controlling operating and maintenance expenses and by increasing revenues in
2002 and 2001.
Capital costs decreased due primarily to interest paid to the IRS in 2000 on a
COLI deduction disallowance and continuing declines in short-term market
interest rate conditions since early 2001.
Volatility in energy commodities markets affects the fair values of all of our
open trading and derivative contracts exposing AEP to market risk and causing
our results of operations to be more volatile. See "Market Risks" section for a
discussion of the policies and procedures AEP uses to manage its exposure to
market and other risks from trading activities.
Revenues Increase
AEP's total revenues increased 14% in 2002 and 15% in 2001. The following table
shows the components of revenues:
For The Year Ended
December 31
--------------------
2002 2001 2000
(in millions)
WHOLESALE:
Residential $ 3,713 $ 3,553 $ 3,511
Commercial 2,156 2,328 2,249
Industrial 1,903 2,388 2,444
Other Retail
Customers 385 419 414
Electricity
Marketing (net) 2,227 802 1,073
Unrealized MTM
Income-Electric 136 210 38
Other 1,397 632 837
Less: Transmission and
Distribution Revenues
Assigned to Energy
Delivery* (3,551) (3,356) (3,174)
------ ------- -------
Wholesale
Electric 8,366 6,976 7,392
------ ------- -------
Gas Marketing (net) 3,021 2,274 310
Unrealized MTM Income
(Loss)-Gas (399) 47 132
------- ------- -------
Wholesale Gas 2,622 2,321 442
------- ------- -------
TOTAL WHOLESALE 10,988 9,297 7,834
------- ------- -------
DOMESTIC ELECTRICITY
DELIVERY:
Transmission 922 1,029 1,009
Distribution 2,629 2,327 2,165
------- ------- -------
TOTAL DOMESTIC
ELECTRICITY
DELIVERY 3,551 3,356 3,174
------- ------- -------
OTHER
INVESTMENTS 16 114 105
------- ------- -------
TOTAL REVENUES $14,555 $12,767 $11,113
======= ======= =======
*Certain revenues in the Wholesale business include energy delivery revenues due
primarily to bundled tariffs that are assignable to the Energy Delivery
business.
The level of electricity transactions tends to fluctuate due to the highly
competitive nature of the short-term (spot) energy market and other factors,
such as affiliated and unaffiliated generating plant availability, weather
conditions and the economy. The FERC's introduction of a greater degree of
competition into the wholesale energy market has had a major effect on the
volume of wholesale power marketing especially in the short-term market.
The increase in 2002 in wholesale revenues resulted from a 27% increase in
trading volume associated with Wholesale Electricity which was offset by a
continuing decrease in gross margins which began in the fourth quarter of 2001,
and an increase in residential sales as a result of favorable weather conditions
in the third quarter 2002. In addition Other Wholesale electric revenues
increased due to the mid-year 2001 acquisition of barging and coal mining
operations as well as the recognition of revenues for generation projects
completed for third parties. The increase in 2002 Wholesale Gas revenues
resulted from a full year of HPL operations compared to a partial year from our
acquisition date in July 2001, offset by a decrease in the results from
financial trading and MTM unrealized losses. Other Investments revenue decreased
in 2002 due to the elimination of factoring of accounts receivable of an
unaffiliated utility.
Prior to the third quarter of 2002, we recorded and reported upon settlement,
sales under forward trading contracts as revenues and purchases under forward
trading contracts as purchased energy expenses. Effective July 1, 2002, we
reclassified such forward trading revenues and purchases on a net basis, as
permitted by EITF 98-10 (see Note 1).
Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in
2001. This decrease was due to the economic slow down which began in late 2001.
Sales to residential customers rose 5% due to weather related demand in 2002.
The economic slow down reduced demand and wholesale prices especially in the
latter part of 2001.
Operating Expenses Increase
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
2002 2001
---- ----
(in millions)
Amount % Amount %
------ - ------ -
Fuel and Purchased
Energy:
Electricity $ 959 43.7 $(1,275) (36.7)
Gas 404 14.7 2,339 570.5
Maintenance and
Other Operation 303 8.2 228 6.5
Non-recoverable
Merger Costs (11) (52.4) (182) (89.7)
Asset Impairments 867 N.M. - -
Depreciation and
Amortization 134 10.8 152 13.9
Taxes Other Than
Income Taxes 51 7.6 (16) (2.3)
------ ------
Total $2,707 25.6 $1,246 13.3
====== ======
The increase in Fuel and Purchased Energy expense was primarily attributable to
an increase in power generation. Net generation increased 6% for Eastern plants
due to increased demand for electricity and a reduction in planned power plant
maintenance outages for various plants as compared to 2001. The return to
service of the Cook Plant's two nuclear generating units in June 2000 and
December 2000 accounted for the increase in nuclear generation. The increase in
Gas expense was primarily due to a full year of HPL operations compared to a
partial year from our acquisition date in July 2001.
The increase in Maintenance and Other Operation expense in 2002 is primarily due
to recognizing a full year's expense for the businesses acquired during 2001
including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and
HPL. In addition, increased administrative costs for the implementation of
customer choice in Texas contributed to the increase. The increase was offset in
part by a reduction in trading incentive compensation and the effect of planned
boiler plant maintenance at various plants in 2001 and less refueling outages
for STP in 2002 than 2001.
Maintenance and Other Operation expense rose in 2001 mainly as a result of
additional traders' incentive compensation and accruals for severance costs
related to corporate restructuring.
With the consummation of the merger with CSW, certain deferred merger costs were
expensed in 2000. The merger costs charged to expense included transaction and
transition costs not allocable to and recoverable from ratepayers under
regulatory commission approved settlement agreements to share net merger
savings. As expected, merger costs declined in 2001 and 2002 after the merger
was consummated.
In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and
investments totaling $1.4 billion (consisting of approximately, $866.6 million
related to asset impairments, $321.1 million related to investment value losses,
and $238.7 million related to discontinued operations) that reflected downturns
in energy trading markets, projected long-term decreases in electricity prices,
and other factors. These impairments exclude the transitional impairment loss
from adoption of SFAS142 (see Note 2). The categories of impairments included:
2002 Pre-Tax Estimated Loss
(in millions)
Asset Impairments
Held for Sale $ 483.1
Asset Impairments
Held and Used 651.4
Investment Value
Losses 291.9
--------
Total $1,426.4
========
Additional market deterioration associated with our non-core wholesale
investments, including our U.K. operations, could have an adverse impact on our
future results of operations and cash flows. Significant long-term changes in
external market conditions could lead to additional write-offs and potential
divestitures of our wholesale investments, including, but not limited to, our
U.K. operations.
The rise in Depreciation and Amortization expense in 2002 resulted from the
amortization of Texas generation related Regulatory Assets that were securitized
in early 2002, businesses acquired in 2001 and additional production plant
placed into service.
Depreciation and Amortization expense increased in 2001 primarily as a result of
the commencement of amortization of transition generation regulatory assets in
the Ohio, Virginia and West Virginia jurisdictions due to passage of
restructuring legislation, the new businesses acquired in 2001 and additional
investments in Property, Plant and Equipment.
Taxes Other Than Income Taxes increased in 2002 due to a full year of state
excise taxes which replaced the state gross receipts tax in Ohio and increased
local franchise taxes in Texas partly offset by the effect of Texas one-time
2001 assessments and decreased gross Texas receipts taxes due to deregulation.
Interest, Preferred Stock Dividends, Minority Interest
The decrease in Interest in 2002 was primarily due to a reduction in short-term
interest rates and lower outstanding balances of short-term debt and the
refinancing of long-term debt at favorable interest rates offset in part by an
increased amount of long-term debt outstanding.
Interest expense decreased 15% in 2001 due to the effect of interest paid to the
IRS on a COLI deduction disallowance in 2000 and lower average outstanding
short-term debt balances and a decrease in average short-term interest rates.
Minority Interest in Finance Subsidiary increased substantially in 2002 because
the distributions to minority interest were in effect for the entire year. In
2001 we issued a preferred member interest to finance the acquisition of HPL and
paid a preferred return of $13 million to the preferred member interest. The
minority interest was only in effect during the last four months of 2001.
Other Income/Other Expenses
Other Income increased by $110 million or 33% in 2002 due to the sale of AEP'S
retail electric providers in Texas and due to non-operational revenue (see Note
1). Other Expenses increased $134 million or 72% in 2002 due to non-operational
expenses (see Note 1).
Other Income increased $240 million in 2001. This increase was primarily caused
by an increase in equity earnings due to acquisitions of $63 million and a $73
million gain from the sale of a generating plant (see Note 1). Other Expenses
increased by $110 million or 143% in 2001 due to costs to exit air
transportation, fiber optic and Datapult businesses (see Note 1).
Income Taxes
The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book
income offset by the tax effects of the sale of foreign operations.
Although pre-tax book income increased considerably in 2001, Income Taxes
decreased due to the effect of recording in 2000 prior year federal income taxes
as a result of the disallowance of COLI interest deductions by the IRS and
nondeductible merger related costs in 2000.
Extraordinary Losses and Cumulative Effect
The loss for transitional goodwill impairment related to SEEBOARD and CitiPower
resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported
as a Cumulative Effect of Accounting Change on January 1, 2002.
In 2001 we recorded an extraordinary loss of $48 million net of tax to write-off
prepaid Ohio excise taxes stranded by Ohio deregulation. The application of
regulatory accounting for generation was discontinued in 2000 for the Ohio,
Virginia and West Virginia jurisdictions which resulted in the after-tax
extraordinary loss of $35 million.
New accounting rules that became effective in 2001 regarding accounting for
derivatives required us to mark-to-market certain fuel supply contracts that
qualify as financial derivatives. The effect of initially adopting the new rules
at July 1, 2001 was a favorable earnings effect of $18 million, net of tax,
which is reported as a Cumulative Effect of Accounting Change.
Discontinued Operations
The operations shown below were discontinued or held for sale in 2002 (See Note
12). Results of operations including impairment losses, net of tax, of these
businesses have been reclassified:
Company 2002 2001 2000
- ------- ---- ---- ----
(in millions)
SEEBOARD $ 96 $ 88 $ 99
CitiPower (123) (6) 17
Pushan (7) 4 7
Eastex (156) - (1)
----- ---- ----
$(190) $ 86 $122
===== ==== ====
Reclassification
Balance sheet amounts have been restated to reflect our change in accounting
policy regarding certain assets and liabilities related to forward physical and
financial transactions (see "Reclassification" discussion Note 1.) Based upon
AEP's legal rights of offset, physical and financial contracts were netted in
2002 and 2001 amounts and financial contracts were netted in 2000 and 1999
amounts. Related assets and liabilities were not netted in 1998 amounts as the
impact is not material.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
- -------------------------------------
(in millions - except per share amounts)
Year Ended December 31,
--------------------------
2002 2001 2000
---- ---- ----
REVENUES:
Wholesale Electricity $ 8,366 $ 6,976 $ 7,392
Wholesale Gas 2,622 2,321 442
Domestic Electricity Delivery 3,551 3,356 3,174
Other Investment 16 114 105
------- ------- -------
TOTAL REVENUES 14,555 12,767 11,113
------- ------- -------
EXPENSES:
Fuel and Purchased Energy:
Electricity 3,154 2,195 3,470
Gas 3,153 2,749 410
------- ------- -------
TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880
Maintenance and Other Operation 4,013 3,710 3,482
Non-recoverable Merger Costs 10 21 203
Asset Impairments 867 - -
Depreciation and Amortization 1,377 1,243 1,091
Taxes Other Than Income Taxes 718 667 683
------- ------- -------
TOTAL EXPENSES 13,292 10,585 9,339
------- ------- -------
OPERATING INCOME 1,263 2,182 1,774
OTHER INCOME 445 335 95
LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 - -
LESS: OTHER EXPENSES 321 187 77
LESS: INTEREST 785 844 999
PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIES 11 10 11
MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 -
------- ------- -------
INCOME BEFORE INCOME TAXES 235 1,463 782
INCOME TAXES 214 546 602
------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS
AND CUMULATIVE EFFECT 21 917 180
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122
EXTRAORDINARY LOSSES (NET OF TAX):
DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - (48) (35)
LOSS ON REACQUIRED DEBT - (2) -
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 -
------- ------- -------
NET INCOME (LOSS) $ (519) $ 971 $ 267
======= ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322
=== === ===
EARNINGS (LOSS) PER SHARE:
Income Before Discontinued Operations, Extraordinary Items
and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56
Discontinued Operations (0.57) 0.26 0.38
Extraordinary Losses - (0.16) (0.11)
Cumulative Effect of Accounting Change (1.06) 0.06 -
------ ------ ------
Earnings (Loss) Per Share (Basic and Diluted) $(1.57) $ 3.01 $ 0.83
====== ====== ======
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
===== ===== =====
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
- ---------------------------
(in millions - except share data)
December 31,
-----------
2002 2001
---- ----
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 1,213 $ 224
Accounts Receivable:
Customers 466 343
Miscellaneous 1,394 1,365
Allowance for Uncollectible Accounts (119) (69)
Fuel, Materials and Supplies 1,166 1,037
Energy Trading and Derivative Contracts 1,046 2,125
Other 935 639
------- -------
TOTAL CURRENT ASSETS 6,101 5,664
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,031 17,054
Transmission 5,882 5,764
Distribution 9,573 9,309
Other (including gas and coal mining assets
and nuclear fuel) 3,965 4,272
Construction Work in Progress 1,406 1,015
------- -------
Total Property, Plant and Equipment 37,857 37,414
Accumulated Depreciation and Amortization 16,173 15,310
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104
------- -------
REGULATORY ASSETS 2,688 3,162
------- -------
SECURITIZED TRANSITION ASSETS 735 -
------- -------
INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633
------- -------
ASSETS HELD FOR SALE 247 721
------- -------
ASSETS OF DISCONTINUED OPERATIONS - 3,954
------- -------
GOODWILL 396 392
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795
------- -------
OTHER ASSETS 1,783 1,872
------- -------
TOTAL ASSETS $34,741 $39,297
======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
December 31,
-----------
2002 2001
---- ----
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,042 $ 1,914
Short-term Debt 3,164 4,011
Long-term Debt Due Within One Year* 1,633 1,095
Energy Trading and Derivative Contracts 1,147 1,877
Other 1,804 1,924
------- -------
TOTAL CURRENT LIABILITIES 9,790 10,821
------- -------
LONG-TERM DEBT* 8,487 8,410
------- -------
EQUITY UNIT SENIOR NOTES 376 -
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603
------- -------
DEFERRED INCOME TAXES 3,916 4,500
------- -------
DEFERRED INVESTMENT TAX CREDITS 455 491
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 185 194
------- -------
OTHER NONCURRENT LIABILITIES 1,903 1,334
------- -------
LIABILITIES HELD FOR SALE 91 87
------- -------
LIABILITIES OF DISCONTINUED OPERATIONS - 2,582
------- -------
COMMITMENTS AND CONTINGENCIES (Note 9)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 321 321
------- -------
MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750
------- -------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 145 156
------- -------
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
2002 2001
---- ----
Shares Authorized. . . . .600,000,000 600,000,000
Shares Issued. . . . . . .347,835,212 331,234,997
(8,999,992 shares were held in treasury
at December 31, 2002 and 2001) 2,261 2,153
Paid-in Capital 3,413 2,906
Accumulated Other Comprehensive Income (Loss) (609) (126)
Retained Earnings 1,999 3,296
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 7,064 8,229
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $34,741 $39,297
======= =======
*See Accompanying Schedules.
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(in millions)
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
OPERATING ACTIVITIES:
Net Income (Loss) $ (519) $ 971 $ 267
Plus: Discontinued Operations 540 (86) (122)
------ ------- ------
Net Income from Continuing Operations 21 885 145
Adjustments for Noncash Items:
Asset Impairments, Investment Value and Other Impairments 1,188 - -
Depreciation and Amortization 1,403 1,277 1,152
Deferred Investment Tax Credits (31) (29) (36)
Deferred Income Taxes (66) 157 (190)
Amortization of Operating Expenses and Carrying Charges 40 40 48
Cumulative Effect of Accounting Change - (18) -
Equity Earnings of Yorkshire Electricity Group plc - - (44)
Extraordinary Loss - 50 35
Deferred Costs Under Fuel Clause Mechanisms (31) 340 (449)
Mark-to-Market of Energy Trading Contracts 263 (257) (170)
Miscellaneous Accrued Expenses 30 (384) 217
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (152) 1,766 (1,530)
Fuel, Materials and Supplies (127) (78) 149
Accrued Revenues (283) 35 (71)
Accounts Payable 52 (478) 1,292
Taxes Accrued (216) (147) 171
Payment of Disputed Tax and Interest Related to COLI - - 319
Change in Other Assets (177) (239) (283)
Change in Other Liabilities (237) (161) 386
------ ------- -------
Net Cash Flows From Operating Activities 1,677 2,759 1,141
------ ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (1,722) (1,654) (1,468)
Purchase of Gas Pipe Line - (727) -
Purchase of U.K. Generation - (943) -
Purchase of Coal Company - (101) -
Purchase of Barging Operations - (266) -
Purchase of Wind Generation - (175) -
Proceeds from Sale of Retail Electric Providers 146 - -
Proceeds from Sale of Foreign Investments 1,117 383 -
Proceeds from Sale of U.S. Generation - 265 -
Other 37 (42) (18)
------ ------- -------
Net Cash Flows Used For Investing Activities (422) (3,260) (1,486)
------ ------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock 656 11 14
Issuance of Minority Interest - 744 -
Issuance of Long-term Debt 2,893 2,863 878
Issuance of Equity Unit Senior Notes 334 - -
Retirement of Cumulative Preferred Stock (10) (5) (21)
Retirement of Long-term Debt (2,514) (1,570) (1,303)
Change in Short-term Debt (net) (829) (790) 1,328
Dividends Paid on Common Stock (793) (773) (805)
Dividends on Minority Interest in Subsidiary - (5) -
------ ------- -------
Net Cash Flows From (Used for) Financing Activities (263) 475 91
------ ------- -------
Effect of Exchange Rate Changes on Cash (3) (1) 30
------ ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 989 (27) (224)
Cash and Cash Equivalents from Continuing Operations - Beginning of Period 224 251 475
------ ------- -------
Cash and Cash Equivalents from Continuing Operations - End of Period $1,213 $ 224 $ 251
====== ======= =======
Net Increase (Decrease) in Cash and Cash Equivalents from
Discontinued Operations $ (100) $ 17 $ (17)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 108 91 108
------ ------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 8 $ 108 $ 91
====== ======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income
- -------------------------------------------------------------------------------
(in millions)
Accumulated
Other
Common Stock Paid-In Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
------ ------ ------- -------- ------------- -----
DECEMBER 31, 1999 331 $2,149 $2,898 $3,630 $ (4) $8,673
Issuances - 3 11 - - 14
Cash Dividends Declared - - - (805) - (805)
Other - - 6 (2) - 4
------
7,886
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (119) (119)
Reclassification Adjustment
For Loss Included in Net Income - - - - 20 20
Net Income - - - 267 267
------
Total Comprehensive Income 168
--- ------ ------ ------ ----- ------
DECEMBER 31, 2000 331 $2,152 $2,915 $3,090 $(103) $8,054
Issuances - 1 9 - - 10
Cash Dividends Declared - - - (773) - (773)
Other - - (18) 8 - (10)
------
7,281
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (14) (14)
Unrealized Gain (Loss) on
Hedged Derivatives (3) (3)
Minimum Pension Liability - - - - (6) (6)
Net Income - - - 971 971
------
Total Comprehensive Income 948
--- ------ ------ ------ ----- ------
DECEMBER 31, 2001 331 $2,153 $2,906 $3,296 $(126) $8,229
Issuances 17 108 568 - - 676
Cash Dividends Declared - - - (793) - (793)
Other - - (61) 15 - (46)
------
(163)
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - 117 117
Unrealized Gain (Loss) on
Hedged Derivatives (13) (13)
Minimum Pension Liability - - - - (585) (585)
Unrealized Loss on Securities Available
For Sale (2) (2)
Net Income (Loss) - - - (519) (519)
------
Total Comprehensive Income (1,002)
--- ------ ------ ------ ----- ------
DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064
=== ====== ====== ====== ===== ======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
December 31, 2002
-----------------
Call
Price per Shares Shares Amount (In
Share(a) Authorized(b) Outstanding(f) Millions)
--------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 608,150 $ 61
----
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 333,100 33
6.02% - 6-7/8% (c) $100 1,650,000 513,450 51
----
Total Subject to Mandatory
Redemptio(C)(c) 84
Total Preferred Stock $145
====
December 31, 2001
-----------------
Call
Price per Shares Shares Amount (In
Share(a) Authorized(b) Outstanding(f) Millions)
--------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 614,608 $ 61
----
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 333,100 33
6.02% - 6-7/8% (c) $100 1,650,000 513,450 52
7% (e) (e) 250,000 100,000 10
----
Total Subject to Mandatory
Redemption (c) 95
----
Total Preferred Stock $156
====
NOTES TO SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call
price plus accrued dividends. The involuntary liquidation preference is
$100 per share for all outstanding shares.
(b) As of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and
7,713,501 shares of $100, $25 and no par value preferred stock,
respectively, that were authorized but unissued. (c) Shares outstanding
and related amounts are stated net of applicable retirements through
sinking funds(generally at par)
and reacquisitions of shares in anticipation of future requirements. The
subsidiaries reacquired enough shares in 1997 to meet all sinking fund
requirements on certain series until 2008 and on certain series until
2009 when all remaining outstanding shares must be redeemed.
(d) Not callable prior to 2003, after that the call price is $100 per share
plus accrued dividends. (e) With sinking fund. (f) The number of shares
of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares
in 2001 and 209,563 shares in 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Long-term Debt of Subsidiaries
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
- -------- ----------------- ----------------------------- -----------
December 31, 2002 2002 2001 2002 2001
----------------- ---- ---- ---- ----
(in millions)
-------------
FIRST MORTGAGE BONDS (a)
2002-2004 6.87% 6.00%-7.85% 6.00%-7.85% $ 648 $ 1,246
2005-2008 6.90% 6.20%-8% 6.20%-8% 463 699
2022-2025 7.66% 6.875%-8.7% 6-7/8%-8.80% 773 850
INSTALLMENT PURCHASE CONTRACTS (b)
2002-2009 4.62% 3.75%-7.70% 1.80%-7.70% 396 446
2011-2030 5.83% 1.35%-8.20% 1.55%-8.20% 1,284 1,234
NOTES PAYABLE (c)
2002-2021 5.54% 3.732%-9.60% 4.048%-9.60% 520 217
SENIOR UNSECURED NOTES
2002-2005 5.53% 2.12%-7.45% 2.31%-7.45% 1,834 1,910
2006-2012 5.91% 4.31%-6.91% 6.125%-6.91% 2,295 1,727
2032-2038 6.64% 6.00%-7-3/8% 7.20%-7-3/8% 690 340
JUNIOR DEBENTURES
2025-2038 7.90% 7.60%-8.72% 7.60%-8.72% 205 618
SECURITIZATION BONDS
2003-2016 5.40% 3.54%-6.25% - 797 -
OTHER LONG-TERM DEBT (d) 247 258
Unamortized Discount (net) (32) (40)
------- -------
Total Long-term Debt
Outstanding 10,120 9,505
Less Portion Due Within One Year 1,633 1,095
------- -------
Long-term Portion $ 8,487 $ 8,410
======= =======
EQUITY UNIT SENIOR NOTES
2007 5.75% 5.75% - $ 376 $ -
======= =======
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) First mortgage bonds are secured by first mortgage liens on electric
property, plant and equipment.
(b) For certain series of installment purchase contracts interest rates are
subject to periodic adjustment. Certain series will be purchased on demand at
periodic interest-adjustment dates. Letters of credit from banks and standby
bond purchase agreements support certain series.
(c) Notes payable represent outstanding promissory notes issued under term loan
agreements and revolving credit agreements with a number of banks and other
financial institutions. At expiration all notes then issued and outstanding are
due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates. (
d) Other long-term debt consists of a liability along with accrued interest for
disposal of spent nuclear fuel(see Note 9 of the Notes to Consolidated Financial
Statements) and financing obligation under sale lease back agreements.
Long-term debt outstanding at December 31, 2002 (includes Equity Unit Senior
Notes) is payable as follows:
(in millions)
2003 $ 1,633
2004 824
2005 993
2006 1,611
2007 1,081
Later Years 4,386
-------
10,528
Unamortized Discount 32
-------
Total $10,496
AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
Index to Combined Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Goodwill and Other Intangible Assets Note 3
Merger Note 4
Nuclear Plant Restart Note 5
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Stock-Based Compensation Note 15
Business Segments Note 16
Risk Management, Financial Instruments And Derivatives Note 17
Income Taxes Note 18
Basic and Diluted Earnings Per Share Note 19
Supplementary Information Note 20
Power and Distribution Projects Note 21
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Minority Interest in Finance Subsidiary Note 26
Equity Units Note 27
Subsequent Events (Unaudited) Note 30
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of American
Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001,
and the related consolidated statements of operations, cash flows and common
shareholders' equity and comprehensive income, for each of the three years in
the period ended December 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of American Electric
Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Company
adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1,
2002.
As discussed in Note 13 to the consolidated financial statements, the Company
recorded certain impairments of goodwill, long-lived assets and other
investments in the fourth quarter of 2002.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
MANAGEMENT'S RESPONSIBILITY
The management of American Electric Power Company, Inc. has prepared the
financial statements and schedules herein and is responsible for the integrity
and objectivity of the information and representations in this annual report,
including the consolidated financial statements. These statements have been
prepared in conformity with accounting principles generally accepted in the
United States of America, using informed estimates where appropriate, to reflect
the Company's financial condition and results of operations. The information in
other sections of the annual report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for determining
that management has fulfilled its obligation in the preparation of the financial
statements and in the ongoing examination of the Company's established internal
control structure over financial reporting. The Audit Committee, which consists
solely of outside directors and which reports directly to the Board of
Directors, meets regularly with management, Deloitte & Touche LLP - independent
auditors and the Company's internal audit staff to discuss accounting, auditing
and reporting matters. To ensure auditor independence, both Deloitte & Touche
LLP and the internal audit staff have unrestricted access to the Audit
Committee.
The financial statements have been audited by Deloitte & Touche LLP, whose
report appears on the previous page. The auditors provide an objective,
independent review as to management's discharge of its responsibilities insofar
as they relate to the fairness of the Company's reported financial condition and
results of operations. Their audit includes procedures believed by them to
provide reasonable assurance that the financial statements are free of material
misstatement and includes an evaluation of the Company's internal control
structure over financial reporting.
AEP GENERATING COMPANY
AEP GENERATING COMPANY
Selected Financial Data
- -----------------------
Year Ended December 31,
----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $213,281 $227,548 $228,516 $217,189 $224,146
Operating Expenses 207,152 220,571 220,092 211,849 215,415
-------- -------- -------- -------- --------
Operating Income 6,129 6,977 8,424 5,340 8,731
Nonoperating Items, Net 3,681 3,484 3,429 3,659 3,364
Interest Charges 2,258 2,586 3,869 2,804 3,149
-------- -------- -------- -------- --------
Net Income $ 7,552 $ 7,875 $ 7,984 $ 6,195 $ 8,946
======== ======== ======== ======== ========
December 31,
-----------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $652,213 $648,254 $642,302 $640,093 $636,460
Accumulated Depreciation 358,174 337,151 315,566 295,065 277,855
-------- -------- -------- -------- --------
Net Electric Utility Plant $294,039 $311,103 $326,736 $345,028 $358,605
======== ======== ======== ======== ========
Total Assets $349,729 $361,341 $374,602 $398,640 $403,892
======== ======== ======== ======== ========
Common Stock and Paid-in Capital $ 24,434 $ 24,434 $ 24,434 $ 30,235 $ 36,235
Retained Earnings 18,163 13,761 9,722 3,673 2,770
-------- -------- -------- -------- --------
Total Common Shareholder's Equity $ 42,597 $ 38,195 $ 34,156 $ 33,908 $ 39,005
======== ======== ======== ======== ========
Long-term Debt (a) $ 44,802 $ 44,793 $ 44,808 $ 44,800 $ 44,792
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $349,729 $361,341 $374,602 $398,640 $403,892
======== ======== ======== ======== ========
(a) Including portion due within one year.
AEP GENERATING COMPANY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------
AEP Generating Company is engaged in the generation and wholesale sale of
electric power to two affiliates under long-term agreements.
Operating Revenues are derived from the sale of Rockport Plant energy and
capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved
long-term unit power agreements. Under the terms of its unit power agreement,
I&M will purchase all of AEGCo's Rockport capacity unless it is sold to other
utilities. A unit power agreement between AEGCo and KPCo expires in 2004. The
KPCo unit power agreement extends until December 31, 2009 for Rockport Plant
Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes operative. The
unit power agreements provide for recovery of costs including a FERC approved
rate of return on common equity and a return on other capital net of temporary
cash investments. Under terms of the unit power agreements, AEGCo accumulates
all expenses monthly and prepares the bills for its affiliates. In the month the
expenses are incurred, AEGCo recognizes the billing revenues and establishes a
receivable from the affiliated companies.
Results of Operations
Net Income decreased $323,000 or 4% as a result of limits on recovery of return
on capital related to operating and in-service ratios of the Rockport Plant.
Operating Revenues Decrease
- ---------------------------
The decrease in Operating Revenues of $14,267,000 or 6% reflects a decrease in
recoverable expenses, primarily fuel.
Operating Expenses Decrease
- ---------------------------
Operating Expenses decreased 6% as follows:
Increase
(Decrease)
(dollars in thousands) From Previous Year
- --------------------- ------------------
Amount %
------ -
Fuel $(13,723) (13)
Other Operation 1,899 17
Maintenance 565 6
Depreciation 137 1
Taxes Other Than Income Taxes (976) (23)
Income Taxes (1,321) (46)
--------
Total $(13,419) (6)
========
The decrease in Fuel expense reflects a decrease in generation and lower average
fuel costs.
Other Operation expense increased due to increased costs for employee benefits
and property insurance.
The increase in Maintenance expense can be attributed to shorter duration of
maintenance outages for boiler inspection and repair in 2001.
Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and
personal property taxes reflecting a favorable change in the law which lowered
the tax for Rockport Plant.
The decrease in Income Taxes attributable to operations is primarily due to a
decrease in pre-tax operating income and a change in estimate for state income
tax accruals.
AEP GENERATING COMPANY
Statements of Income
- --------------------
Year Ended December 31,
-----------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES $213,281 $227,548 $228,516
-------- -------- --------
OPERATING EXPENSES:
Fuel 89,105 102,828 102,978
Rent - Rockport Plant Unit 2 68,283 68,283 68,283
Other Operation 12,924 11,025 10,295
Maintenance 9,418 8,853 9,616
Depreciation 22,560 22,423 22,162
Taxes Other Than Income Taxes 3,281 4,257 3,854
Income Taxes 1,581 2,902 2,904
-------- -------- --------
TOTAL OPERATING EXPENSES 207,152 220,571 220,092
-------- -------- --------
OPERATING INCOME 6,129 6,977 8,424
NONOPERATING INCOME 343 30 6
NONOPERATING EXPENSES 198 16 17
NONOPERATING INCOME TAX CREDITS 3,536 3,470 3,440
INTEREST CHARGES 2,258 2,586 3,869
-------- -------- --------
NET INCOME $ 7,552 $ 7,875 $ 7,984
======== ======== ========
Statements of Retained Earnings
Year Ended December 31,
----------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $13,761 $ 9,722 $3,673
NET INCOME 7,552 7,875 7,984
CASH DIVIDENDS DECLARED 3,150 3,836 1,935
------- ------- ------
RETAINED EARNINGS DECEMBER 31 $18,163 $13,761 $9,722
======= ======= ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Balance Sheets
- --------------
December 31,
-----------------------------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $637,095 $638,297
General 4,728 3,012
Construction Work in Progress 10,390 6,945
-------- --------
Total Electric Utility Plant 652,213 648,254
Accumulated Depreciation 358,174 337,151
-------- -------
NET ELECTRIC UTILITY PLANT 294,039 311,103
-------- -------
OTHER PROPERTY AND INVESTMENTS 119 119
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents - 983
Accounts Receivable:
Affiliated Companies 18,454 22,344
Miscellaneous - 147
Fuel 20,260 15,243
Materials and Supplies 4,913 4,480
Prepayments - 244
-------- --------
TOTAL CURRENT ASSETS 43,627 43,441
-------- --------
REGULATORY ASSETS 4,970 5,207
-------- --------
DEFERRED CHARGES 6,974 1,471
-------- --------
TOTAL ASSETS $349,729 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 18,163 13,761
-------- --------
Total Common Shareholder's Equity 42,597 38,195
Long-term Debt 44,802 44,793
-------- --------
TOTAL CAPITALIZATION 87,399 82,988
-------- --------
OTHER NONCURRENT LIABILITIES 301 76
-------- --------
CURRENT LIABILITIES:
Advances from Affiliates 28,034 32,049
Accounts Payable:
General 26 7,582
Affiliated Companies 15,907 1,654
Taxes Accrued 2,327 4,777
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 1,111 3,481
-------- --------
TOTAL CURRENT LIABILITIES 52,368 54,506
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 111,046 116,617
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credits 52,943 56,304
Amounts Due to Customers for Income Taxes 16,670 22,725
-------- --------
TOTAL REGULATORY LIABILITIES 69,613 79,029
-------- --------
DEFERRED INCOME TAXES 29,002 27,975
-------- --------
DEFERRED CREDITS - 150
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $349,729 $361,341
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Statements of Cash Flows
- ------------------------
Year Ended December 31,
-------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 7,552 $ 7,875 $ 7,984
Adjustments for Noncash Items:
Depreciation 22,560 22,423 22,162
Deferred Income Taxes (5,028) (6,224) (5,842)
Deferred Investment Tax Credits (3,361) (3,414) (3,396)
Amortization of Deferred Gain on Sale and
Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571)
Change in Certain Current Assets and Liabilities:
Accounts Receivable 4,037 1,224 1,392
Fuel, Materials and Supplies (5,450) (4,738) 6,486
Accounts Payable 6,697 (4,597) (13,157)
Taxes Accrued (2,450) (216) 708
Other Assets (5,211) (569) 1,636
Other Liabilities (2,295) (1,244) (404)
-------- -------- --------
Net Cash Flows From Operating Activities 11,480 4,949 11,998
-------- -------- --------
INVESTING ACTIVITIES - Construction Expenditures (5,298) (6,868) (5,190)
-------- -------- --------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - - (5,801)
Change in Short-term Debt (net) - - (24,700)
Change in Advances From Affiliates (net) (4,015) 3,981 28,068
Dividends Paid (3,150) (3,836) (1,935)
-------- -------- --------
Net Cash Flows From (Used For)
Financing Activities (7,165) 145 (4,368)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (983) (1,774) 2,440
Cash and Cash Equivalents January 1 983 2,757 317
-------- -------- --------
Cash and Cash Equivalents December 31 $ - $ 983 $ 2,757
======== ======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $2,019,000, $1,509,000 and
$3,531,000 and for income taxes was $7,884,000, $8,597,000 and $6,820,000 in
2002, 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Statements of Capitalization
- ----------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON STOCK EQUITY (a) $42,597 $38,195
------- -------
LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
Series Due Date
1995 A, 2025 (c) 22,500 22,500
1995 B, 2025 (c) 22,500 22,500
Unamortized Discount (198) (207)
------- -------
TOTAL LONG-TERM DEBT 44,802 44,793
------- -------
TOTAL CAPITALIZATION $87,399 $82,988
======= =======
(a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There
were no other material transactions affecting Common Stock and Paid-in Capital
in 2002, 2001 and 2000. (b) Installment purchase contracts were entered into in
connection with the issuance of pollution control revenue bonds by the City of
Rockport, Indiana. The terms of the installment purchase contracts require AEGCo
to pay amounts sufficient to enable the payment of interest and principal on the
related pollution control revenue bonds issued to refinance the construction
costs of pollution control facilities at the Rockport Plant.
(c) These series have an adjustable interest rate that can be a daily, weekly,
commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001,
AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and
averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of
4.05% for five years ending July 12, 2006.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------
The notes to AEGCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to AEGCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Effects of Regulation Note 7
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors
of AEP Generating Company:
We have audited the accompanying balance sheets and statements of capitalization
of AEP Generating Company as of December 31, 2002 and 2001, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of AEP Generating Company as of December 31,
2002 and 2001, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
Year Ended December 31,
----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,690,493 $1,738,837 $1,770,402 $1,482,475 $1,406,117
Operating Expenses 1,296,760 1,443,106 1,463,304 1,188,490 1,123,330
--------- --------- --------- --------- ---------
Operating Income 393,733 295,731 307,098 293,985 282,787
Nonoperating Items, Net 8,079 5,324 7,235 8,113 760
Interest Charges 125,871 116,268 124,766 114,380 122,036
------- --------- ------- ------- ---------
Income Before
Extraordinary Item 275,941 184,787 189,567 187,718 161,511
Extraordinary Loss - (2,509) - (5,517) -
--------- --------- --------- -------- ---------
Net Income 275,941 182,278 189,567 182,201 161,511
Preferred Stock
Dividend
Requirements 241 242 241 6,931 6,901
Gain (Loss) on
Reacquired Preferred
Stock 4 - - (2,763) -
--------- --------- --------- -------- --------
Earnings Applicable
To Common Stock $275,704 $182,036 $189,326 $172,507 $154,610
======== ======== ======== ======== ========
Year Ended December 31,
----------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,625,736 $5,769,707 $5,592,444 $5,511,894 $5,336,191
Accumulated
Depreciation
And Amortization 2,405,492 2,446,027 2,297,189 2,247,225 2,072,686
--------- ---------- --------- --------- ---------
Net Electric Utility
Plant $3,220,244 $3,323,68 $3,295,255 $3,264,669 $3,263,505
========== ========== ========== ========== ==========
Total Assets $5,356,438 $4,893,030 $5,467,701 $4,847,857 $4,735,656
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $187,898 $ 573,903 $573,904 $573,904 $573,904
Accumulated Other
Comprehensive
Income (Loss) (73,160) - - - -
Retained Earnings 986,396 826,197 792,219 758,894 734,387
------- ---------- ------- ------- -------
Total Common
Shareholder's Equity $1,101,134 $1,400,100 $1,366,123 $1,332,798 $1,308,291
========== ========== ========== ========== ==========
Preferred Stock $ 5,942 $ 5,952 $ 5,951 $ 5,951 $163,188
======= ========== ======= ======= ========
CPL - Obligated,
Mandatorily
Redeemable Preferred
Securities of
Subsidiary Trust
Holding Solely
Junior Subordinated
Debentures of CPL
$136,250 $ 136,250 $148,500 $150,000 $150,000
======== ========= ======== ======== ========
Long-term Debt (a) $1,438,565 $1,253,768 $1,454,559 $1,454,541 $1,350,706
========== ========== ========== ========== ==========
Total Capitalization
And Liabilities $5,356,438 $4,893,030 $5,467,701 $4,847,857 $4,735,656
========== ========== ========== ========== ==========
(a) Including portion due within one year.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------
AEP Texas Central Company (TCC), formerly known as Central Power and Light
Company (CPL), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in southern Texas. TCC also
sells electric power at wholesale to other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to its affiliated retail electric
provider (REP) in Texas.
Wholesale power marketing activities are conducted on TCC's behalf by AEPSC.
TCC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.
On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.
Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TCC submitted a plan for separation that was subsequently approved by the
PUCT. TCC has functionally separated its generation from its transmission and
distribution operations and AEP formed a separate affiliated REP. Pending
regulatory approval, TCC anticipates legally separating its generation from its
transmission and distribution operations (see Note 8). The affiliated REP, a
separate legal entity that was an AEP subsidiary (not owned by or consolidated
with TCC) was sold in December 2002 (see Note 12).
Since the affiliated REP is the electricity supplier to retail customers in the
ERCOT area, TCC sells its generation to the affiliated REP and other market
participants and provides transmission and distribution services to retail
customers of the REPs in the TCC service territory. As a result of the formation
of the affiliated REP, effective January 1, 2002, TCC no longer supplies
electricity directly to retail customers. The implementation of REPs as
suppliers to retail customers has caused a significant shift in TCC's sales as
described below under "Results of Operations."
In December 2002, AEP sold the affiliated REP to an unrelated third party who
assumed the obligations of the affiliated REP under the Texas Restructuring
Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated
REP were classified as Sales to AEP Affiliates. Subsequent to the sale,
transactions with the REP were classified as Wholesale Electricity or Energy
Delivery.
Results of Operations
- ---------------------
In 2002, Net Income increased $94 million or 51% primarily due to $262 million
of revenues associated with recognition of stranded costs in Texas offset in
part by losses associated with the commencement of customer choice in Texas
which resulted in the loss of customers and reduced prices (see Note 8). In
2001, Income Before Extraordinary Item decreased $5 million or 3%, primarily
resulting from a settlement of Texas municipal franchise fees and increased
Maintenance expenses.
Changes in Operating Revenues
- -----------------------------
Increase (Decrease)
From Previous Year
(dollars in millions)
---------------------
2002 2001
Amount % Amount %
------ - ------ -
Wholesale
Electricity* $(1,096.4) (90) $(29.9) (2)
Energy Delivery* 81.4 17 (5.6) (1)
Sales to AEP
Affiliates 966.7 N.M. 4.0 11
-------- ------
Total $ (48.3) (3) $(31.5) (2)
======= ======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
N.M. = Not Meaningful
In 2002, Wholesale Electricity revenues decreased as a result of the elimination
of TCC's retail electricity sales in the ERCOT region as of January 1, 2002 and
a decrease in wholesale power marketing margins offset in part by the
interchange cost reconstruction (ICR) adjustments (see Note 6). In 2001, the
decrease in Wholesale Electricity revenues was primarily attributable to
unfavorable wholesale power marketing and trading conditions.
In 2002, Sales to AEP Affiliates revenue increased primarily due to increased
revenues from the newly created affiliated REP. Although TCC sold electricity to
the affiliated REP instead of directly to retail customers, total revenues
decreased due to lower prices for power sold to the affiliated REP.
Additionally, delivery charges provided to the affiliated REP in 2002 are
classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were
classified as Energy Delivery revenue. Revenues for 2002 included $262 million
of revenues, associated with recognition of stranded costs in Texas (see Note
8). Energy Delivery revenue also included revenues received for securitized
assets beginning in 2002 (see Note 8).
Changes in Operating Expenses
- -----------------------------
Increase (Decrease)
From Previous Year
(dollars in millions)
---------------------
2002 2001
Amount % Amount %
------ - ------ -
Fuel $(246.2) (50) $(58.8) (11)
Purchased
Power:
Wholesale
Electricity
83.5 65 (16.2) (11)
AEP Affiliates (35.3) (60) 26.0 80
Other
Operation (17.1) (5) 1.7 1
Maintenance (7.8) (11) 10.7 18
Depreciation
And
Amortization
45.8 27 (10.4) (6)
Taxes Other
Than
Income
Taxes
4.6 5 14.4 19
Income
Taxes 26.1 23 12.4 12
------- ------
Total $(146.4) (10) $(20.2) (1)
======= ======
In 2002, the decrease in Fuel expense was due to a decrease in the average unit
cost of fuel and decreased generation. The decrease in Fuel expense in 2001 was
primarily due to a reduction in the average cost of fuel primarily from a
decline in natural gas prices. TCC used natural gas as fuel for 32% of its
generation in 2002. The nature of the natural gas market is such that both
long-term and short-term contracts are generally based on the current spot
market price. Changes in natural gas prices affect TCC's fuel expense; however,
they generally did not impact results of operations in 2001 and 2000 due to fuel
recovery mechanisms, which are no longer in place beginning with deregulation in
2002.
In 2002, the increase in Wholesale Electricity Purchased Power expense is due to
higher MWH purchases from the market where we could purchase power at prices
lower than our cost to produce. ICR adjustments also had the effect of
increasing Wholesale Electricity Purchased Power expense and decreasing AEP
Affiliates Purchased Power expense in 2002 (see Note 6).
In 2001, Purchased Power increased overall largely due to higher natural gas
prices. Although gas prices declined in 2001, they were higher during the first
half of 2001 when TCC was making most of its purchases.
In 2002, Other Operation expense decreased due primarily to the elimination of
factoring of accounts receivable and lower ERCOT transmission related expenses.
In 2002, Maintenance expense decreased due to two scheduled "18 month interval"
refueling outages for STP during 2001 that increased Maintenance expense above
the 2002 and 2000 levels. Also contributing to the decrease in 2002, and the
increase in 2001, was an increase in Maintenance expense for scheduled major
overhauls of four power plants in 2001.
In 2002, the increase in Depreciation and Amortization is attributable to the
amortization of regulatory assets that were securitized in the first quarter of
2002, offset by the elimination of excess earnings expense in 2002 under Texas
Restructuring Legislation (see Note 8).
In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from
higher local franchise taxes, offset by one-time 2001 assessments and decreased
gross receipts tax, due to deregulation. In 2001, Taxes Other Than Income Taxes
increased due primarily to an increase in franchise related taxes, including a
settlement of disputed franchise fees, and a new tax levied by the PUCT, the
Texas System Benefit Fund Assessment.
In 2002, the increase in Income Taxes is due to an increase in pre-tax income
offset by changes in timing between book/tax accounting differences in state
income taxes. In 2001 the increase in Income Tax expense is primarily due to
adjustments associated with prior year tax returns and an increase in pre-tax
book income.
Other Changes
- -------------
In 2002, Nonoperating Income and Nonoperating Expenses increased significantly
as a result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties, offset in part by decreased
interest income. The revenues associated with the energy related construction
projects included in Nonoperating Income increased $34 million and $15 million
in 2002 and 2001. The expenses associated with these projects included in
Nonoperating Expenses increased $32 million and $14 million in 2002 and 2001.
In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax
non-operating income.
In 2002, Interest Charges increased primarily due to higher levels of
outstanding debt (see TCC's schedule of Long-term Debt and Consolidated
Statements of Capitalization for further information). In 2001, the decrease in
interest charges was attributable to lower average interest rates associated
with short-term and long-term debt.
Extraordinary Loss
- ------------------
The extraordinary loss on reacquired debt recorded in 2001 was the result of
reacquisition of installment purchase contracts for Matagorda County, Navigation
District, Texas.
Impairment
- ----------
As a result of TCC's recent ability to purchase electricity at a significantly
lower price than its current cost to generate electricity, TCC proposed in
September 2002 to "inactivate" various, high-cost gas fired generating
facilities. In the third quarter 2002, TCC recorded an impairment charge of
approximately $95.6 million (pre-tax) related to these plants and recorded
approximately $4.0 million (pre-tax) for severance charges. Both of these
charges were deferred and recorded in Regulatory Assets Designated for or
Subject to Securitization, to be included as a stranded cost in the Texas 2004
true-up proceeding (see Note 8). In the fourth quarter 2002 an additional
pre-tax charge of $21.6 million was recorded related to additional plant
impairments, fuel inventory and materials and supplies, and an additional $1.5
million pre-tax charge was recorded related to severance charges (see Note 13)
related to the "inactivated" plants. The entire $23.1 million was also deferred
and recorded in Regulatory Assets Designated for or Subject to Securitization.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $ 127,502 $1,223,893 $1,253,836
Energy Delivery 554,547 473,182 478,814
Sales to AEP Affiliates 1,008,444 41,762 37,752
---------- ---------- ----------
TOTAL OPERATING REVENUES 1,690,493 1,738,837 1,770,402
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 245,834 492,057 550,903
Purchased Power:
Wholesale Electricity 211,358 127,816 144,021
AEP Affiliates 23,406 58,641 32,591
Other Operation 304,094 321,227 319,539
Maintenance 63,392 71,212 60,528
Depreciation and Amortization 214,162 168,341 178,786
Taxes Other Than Income Taxes 95,500 90,916 76,477
Income Taxes 139,014 112,896 100,459
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,296,760 1,443,106 1,463,304
---------- ---------- ----------
OPERATING INCOME 393,733 295,731 307,098
NONOPERATING INCOME 53,141 22,552 5,830
NONOPERATING EXPENSES 41,910 17,626 3,668
NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,152 (398) (5,073)
INTEREST CHARGES 125,871 116,268 124,766
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567
EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001) - (2,509) -
---------- ---------- ----------
NET INCOME 275,941 182,278 189,567
PREFERRED STOCK DIVIDEND REQUIREMENTS 241 242 241
GAIN ON REACQUIRED PREFERRED STOCK 4 - -
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 275,704 $ 182,036 $ 189,326
========== ========== ==========
Consolidated Statements of Comprehensive Income
- -----------------------------------------------
Year Ended December 31,
------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $275,941 $182,278 $189,567
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (36) - -
Minimum Pension Liability (73,124) - -
-------- -------- --------
COMPREHENSIVE INCOME $202,781 $182,278 $189,567
======== ======== ========
The common stock of TCC is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------
Year Ended December 31,
---------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $826,197 $792,219 $758,894
NET INCOME 275,941 182,278 189,567
DEDUCTIONS (ADDITIONS):
Capital Stock Gains (4) - -
Cash Dividends Declared:
Common Stock 115,505 148,057 156,000
Preferred Stock 241 242 241
Other - 1 1
-------- -------- --------
BALANCE AT END OF PERIOD $986,396 $826,197 $792,219
======== ======== ========
The common stock of TCC is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,903,942 $3,169,421
Transmission 698,964 663,655
Distribution 1,296,731 1,279,037
General 258,386 241,137
Construction Work in Progress 200,947 169,075
Nuclear Fuel 266,766 247,382
------- -------
Total Electric Utility Plant 5,625,736 5,769,707
Accumulated Depreciation and Amortization 2,405,492 2,446,027
--------- ---------
NET ELECTRIC UTILITY PLANT 3,220,244 3,323,680
--------- ---------
OTHER PROPERTY AND INVESTMENTS 3,977 47,950
----- ------
SECURITIZED TRANSITION ASSETS 734,591 -
------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4,392 28,039
----- ------
CURRENT ASSETS:
Cash and Cash Equivalents 85,420 10,909
Accounts Receivable:
General 113,543 38,459
Affiliated Companies 121,324 6,249
Allowance for Uncollectible Accounts (346) (186)
Fuel Inventory 32,563 38,690
Materials and Supplies 51,593 55,475
Accrued Utility Revenues 27,150 -
Energy Trading and Derivative Contracts 22,493 34,480
Prepayments and Other Current Assets 2,133 2,742
----- -----
TOTAL CURRENT ASSETS 455,873 186,818
------- -------
REGULATORY ASSETS 458,552 226,812
------- -------
REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 336,444 959,294
------- -------
NUCLEAR DECOMMISSIONING TRUST FUND 98,474 98,600
------ ------
DEFERRED CHARGES 43,891 21,837
------ ------
TOTAL ASSETS $5,356,438 $4,893,030
========== ==========
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares at December 31, 2002 6,755,535 Shares at
December 31, 2001 $ 55,292 $ 168,888
Paid-in Capital 132,606 405,015
Accumulated Other Comprehensive Income (Loss) (73,160) -
Retained Earnings 986,396 826,197
--------- ---------
Total Common Shareholder's Equity 1,101,134 1,400,100
Preferred Stock 5,942 5,952
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of CPL 136,250 136,250
Long-term Debt 1,209,434 988,768
--------- -------
TOTAL CAPITALIZATION 2,452,760 2,531,070
--------- ---------
OTHER NONCURRENT LIABILITIES 74,572 10,905
--------- ---------
CURRENT LIABILITIES:
Short-term Debt - Affiliates 650,000 -
Long-term Debt Due Within One Year 229,131 265,000
Advances from Affiliates (net) 126,711 354,277
Accounts Payable - General 72,199 65,307
Accounts Payable - Affiliated Companies 36,242 49,301
Customer Deposits 666 26,744
Taxes Accrued 24,791 83,512
Interest Accrued 51,205 23,715
Energy Trading and Derivative Contracts 19,811 40,987
Other 36,698 18,076
------ ------
TOTAL CURRENT LIABILITIES 1,247,454 926,919
--------- -------
DEFERRED INCOME TAXES 1,261,252 1,163,795
--------- ---------
DEFERRED INVESTMENT TAX CREDITS 117,686 122,892
------- -------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,713 17,675
----- ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 201,001 119,774
------- -------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $5,356,438 $4,893,030
========== ==========
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
Year Ended December 31,
-------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $275,941 $182,278 $189,567
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
Activities:
Depreciation and Amortization 214,162 168,341 178,786
Extraordinary Loss on Reacquired Debt - 2,509 -
Deferred Income Taxes 113,655 (72,568) 16,263
Deferred Investment Tax Credits (5,206) (5,208) (5,207)
Mark-toMarket Energy Trading and Derivative Contracts (1,558) (12,048) 8,191
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (189,999) 52,862 (32,902)
Fuel, Materials and Supplies (4,899) (18,215) 8,680
Interest Accrued 27,490 (2,502) 11,494
Accrued Utility Revenues (27,150) - -
Accounts Payable (6,167) (55,311) 45,873
Taxes Accrued (58,721) 27,986 14,405
Fuel Recovery 16,455 179,866 (96,872)
Transmission Coordination Agreement Settlement - - 15,519
Texas Wholesale Clawback (see Note 7) (262,000) - -
Change in Other Assets (534) 10,767 589
Change in Other Liabilities 56,024 11,163 12,243
-------- -------- --------
Net Cash Flows From Operating Activities 147,493 469,920 366,629
-------- -------- --------
INVESTING ACTIVITIES:
Construction Expenditures (151,645) (193,732) (199,484)
Proceeds From Sales of Property and Other 143 (354) -
-------- -------- --------
Net Cash Flows Used For Investing
Activities (151,502) (194,086) (199,484)
-------- -------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 797,335 260,162 149,248
Change in Short-term Debt Affiliate (Net) 650,000 - -
Retirement of Common Stock (386,005) - -
Retirement of Preferred Stock (6) - -
Retirement of Long-term Debt (639,492) (475,606) (151,440)
Change in Advances from Affiliates (net) (227,566) 84,565 (52,446)
Special Deposit for Reacquisition of Long-term Debt - - 50,000
Dividends Paid on Common Stock (115,505) (148,057) (156,000)
Dividends Paid on Cumulative Preferred Stock (241) (242) (249)
-------- -------- --------
Net Cash Flows From (Used For)
Financing Activities 78,520 (279,178) (160,887)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents
74,511 (3,344) 6,258
Cash and Cash Equivalents January 1 10,909 14,253 7,995
-------- -------- --------
Cash and Cash Equivalents December 31 $ 85,420 $ 10,909 $ 14,253
======== ======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts (including distributions on
Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and
for income taxes was $95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and
2000,respectively.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY (a) $1,101,134 $1,400,100
---------- ----------
PREFERRED STOCK - 3,035,000 authorized shares, $100 par value
Not Subject to Mandatory Redemption:
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
- ------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
4.00% $105.75 100 - - 41,938 4,194 4,204
4.20% 103.75 - - - 17,476 1,748 1,748
---------- ----------
Total Preferred Stock 5,942 5,952
---------- ----------
TRUST PREFERRED SECURITIES:
TCC-obligated, mandatorily redeemable preferred
securities of subsidiary trust holding solely
Junior Subordinated Debentures of TCC, 8.00%,
due April 30, 2037 136,250 136,250
---------- ----------
LONG-TERM (See Schedule of Long-term Debt):
First Mortgage Bonds 152,353 614,200
Securitization Bonds (a) 796,635 -
Installment Purchase Contracts 489,577 489,568
Senior Unsecured Notes - 150,000
Less Portion Due Within One year (229,131) (265,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,209,434 988,768
---------- ----------
TOTAL CAPITALIZATION $2,452,760 $2,531,070
========== ==========
(a) In February 2002, TCC issued securitization bonds. $386 million of the proceeds was used to retire 4,543,857 shares of
common stock.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
2002 2001
---- ----
(in thousands)
% Rate Due
7.25 2004 - October 1 $ 27,400 $100,000
7.50 2002 - December 1 - 115,000
6-7/8 2003 - February 1 16,418 49,200
7-1/8 2008 - February 1 18,581 75,000
7.50 2023 - April 1 17,996 75,000
6-5/8 2005 - July 1 71,958 200,000
-------- --------
Total $152,353 $614,200
======== ========
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.
Securitization Bonds outstanding were as follows:
December 31,
------------------
Final 2002 2001
---- ----
Payment Maturity (in thousands)
Rate Date Date
- ---- --------- ------------
3.54 1/15/2005 1/15/2007 $128,950 $ -
5.01 1/15/2008 1/15/2010 154,507 -
5.56 1/15/2010 1/15/2012 107,094 -
5.96 7/15/2013 7/15/2015 214,927 -
6.25 1/15/2016 1/15/2017 191,857 -
Unamortized Discount (700) -
-------- -----
Total $796,635 $ -
======== =====
In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of
TCC, issued $797 million of Securitization Bonds, Series 2002-1. The
Securitization Bonds mature at different times through 2017 and have a weighted
average interest rate of 5.4 percent.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
2002 2001
---- ----
(in thousands)
% Rate Due
Matagorda County
Navigation District,
Texas:
6.00 2028 - July 1 $120,265 $120,265
6-1/8 2030 - May 1 60,000 60,000
3.75 2030(a) - May 1 111,700 111,700
4.00 2030(a) - May 1 50,000 50,000
4.55 2029(a) - Nov 1 100,635 100,635
Guadalupe-Blanco
River Authority
District, Texas:
(b) 2015 - November 1 40,890 40,890
Red River Authority
District, Texas:
6.00 2020 - June 1 6,330 6,330
Unamortized Discount (243) (252)
-------- --------
Total $489,577 $489,568
======== ========
(a)Installment Purchase Contract provides for bonds to be tendered in 2003 for
3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these
installment purchase contracts have been classified for payments in those years.
(b) A floating interest rate is determined monthly. The rate on December 31,
2002 was 1.7%.
Under the terms of the installment purchase contracts, TCC is required to pay
amounts sufficient to enable the payment of interest on and the principal (at
stated maturities and upon mandatory redemptions) of related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2002 2001
---- ----
(in thousands)
% Rate Due
2002 - February 22 (c) $ - $150,000
------ --------
Total $ - $150,000
====== ========
(c) A floating interest rate is determined monthly. The rate on December 31,
2001 was 2.56%.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $229,131
2004 75,951
2005 121,937
2006 152,900
2007 52,729
Later Years 806,860
----------
Total Principal Amount 1,439,508
Unamortized Discount (943)
----------
Total $1,438,565
See Note 25 for discussion of the Trust Preferred Securities issued by a wholly
owned statutory business trust of TCC.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------
The notes to TCC's consolidated financial statements are combined with the notes
to financial statements for AEP and its other subsidiary registrants. Listed
below are the combined notes that apply to TCC. The combined footnotes begin on
page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Asset Impairment and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of AEP Texas Central Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of AEP Texas Central Company and subsidiaries as of
December 31, 2002 and 2001, and the related consolidated statements of income,
comprehensive income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of AEP Texas Central Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
AEP TEXAS NORTH COMPANY
AEP TEXAS NORTH COMPANY
Selected Financial Data
- -----------------------
Year Ended December 31,
------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 450,740 $556,458 $571,064 $445,709 $424,953
Operating Expenses 442,869 523,068 518,723 391,910 365,677
---------- -------- -------- -------- --------
Operating Income 7,871 33,390 52,341 53,799 59,276
Nonoperating Items, Net (703) 2,195 (1,675) 2,488 2,712
Interest Charges 20,845 23,275 23,216 24,420 24,263
---------- -------- -------- -------- --------
Income (Loss) Before
Extraordinary Item (13,677) 12,310 27,450 31,867 37,725
Extraordinary Loss - - - (5,461) -
---------- -------- -------- -------- --------
Net Income (Loss) (13,677) 12,310 27,450 26,406 37,725
Preferred Stock
Dividend Requirements 104 104 104 104 104
---------- -------- -------- -------- --------
Earnings (Loss) Applicable to
Common Stock $ (13,781) $ 12,206 $ 27,346 $ 26,302 $ 37,621
========== ======== ======== ======== ========
December 31,
-----------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,201,747 $1,260,872 $1,229,339 $1,182,544 $1,146,582
Accumulated
Depreciation and
Amortization 521,792 546,162 515,041 495,847 473,503
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $679,955 $714,710 $714,298 $686,697 $673,079
======== ======== ======== ======== ========
Total Assets $877,175 $ 864,875 $1,087,504 $861,205 $819,446
======== ========== ========== ======== ========
Common Stock and
Paid-in Capital $139,565 $139,565 $139,565 $139,565 $139,565
Accumulated Other Comprehensive
Income (Loss) (30,763) - - - -
Retained Earnings 71,942 105,970 122,588 113,242 114,940
--------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $180,744 $245,535 $262,153 $252,807 $254,505
======== ======== ======== ======== ========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $2,367 $ 2,367 $ 2,367 $ 2,367 $ 2,368
====== ======= ======= ======= =======
Long-term Debt (a) $132,500 $255,967 $255,843 $303,686 $303,518
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $877,175 $ 864,875 $1,087,504 $861,205 $819,446
======== ========== ========== ======== ========
(a) Including portion due within one year.
AEP TEXAS NORTH COMPANY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------
AEP Texas North Company (TNC), formerly known as West Texas Utilities Company
(WTU), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in west and central Texas. TNC
also sells electric power at wholesale to other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to its affiliated retail electric
provider (REP) in Texas.
Wholesale power marketing activities are conducted on TNC's behalf by AEPSC.
TNC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.
On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in
both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the
majority of its operations being in the ERCOT territory.
Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TNC submitted a plan for separation that was subsequently approved by the
PUCT. TNC has functionally separated its generation from its transmission and
distribution operations and AEP formed a separate affiliated REP. Pending
regulatory approval, TNC anticipates legally separating its generation from its
transmission and distribution operations (see Note 8). The affiliated REP, a
separate legal entity that was an AEP subsidiary (not owned by or consolidated
with TNC) was sold in December 2002 (see Note 12).
Since the affiliated REP is the electricity supplier to retail customers in the
ERCOT area, TNC sells its generation to the affiliated REP and other market
participants and provides transmission and distribution services to retail
customers of the REPs in the TNC service territory. As a result of the formation
of the affiliated REP, effective January 1, 2002, TNC no longer supplies
electricity directly to retail customers. The implementation of REPs as
suppliers to retail customers has caused a significant shift in TNC's sales as
described below under "Results of Operations."
In December 2002, AEP sold the affiliated REP to an unrelated third party, who
assumed the obligations of the affiliated REP under the Texas Restructuring
Legislation (see Note 12). Prior to the sale, during 2002, sales to the
affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the
sale, transactions with the REP will be classified as Wholesale Electricity or
Energy Delivery.
Results of Operations
- ---------------------
In 2002, Net Income decreased $26.0 million or 211% primarily due to a $38.1
million long-lived asset impairment charge ($24.8 million net of tax) related to
the inactivation of inefficient gas fired plants (see Note 13) and a $4.7
million impairment charge ($3.1 million net of tax) related to the abandonment
of a wind-powered generation facility (see Note 13).
Changes in Operating Revenues
- -----------------------------
Increase (Decrease) From Previous Year
--------------------------------------
(in millions) %
Wholesale Electricity* $(231.7) (63)
Energy Delivery* (95.7) (57)
Sales to AEP
Affiliates 221.7 N.M.
-------
Total $(105.7) (19)
=======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
N.M. = Not Meaningful
Wholesale Electricity revenues decreased as a result of the elimination of TNC's
retail electricity sales in the ERCOT region as of January 1, 2002 and a
decrease in wholesale power marketing margins, partially offset by the ICR
adjustments (see Note 6).
Sales to AEP Affiliates increased primarily due to increased revenues from the
newly created affiliated REP. Although TNC sold electricity to the affiliated
REP instead of directly to retail customers in the ERCOT region, total revenues
decreased due to lower prices for power sold to the affiliated REP.
Additionally, delivery charges provided to the affiliated REP in 2002 are
classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were
classified as Energy Delivery revenue.
Changes in Operating Expenses
- -----------------------------
Increase (Decrease) From Previous Year
--------------------------------------
(in millions) %
Fuel $(76.7) (43)
Purchased Power:
Wholesale Electricity 10.0 14
AEP Affiliates (19.1) (34)
Other Operation (6.3) (6)
Asset Impairments 42.9 N.M.
Maintenance - -
Depreciation and
Amortization (7.1) (14)
Taxes Other
Than Income Taxes (5.8) (21)
Income Taxes (18.1) N.M.
-----
Total $(80.2) (15)
======
N.M. = Not Meaningful
Fuel expense decreased due to a decrease in the average unit cost of fuel and
decreased generation required due to decreased energy sales. TNC used natural
gas as fuel for 42% of its generation in 2002. The nature of the natural gas
market is such that both long-term and short-term contracts are generally based
on the current spot market price. Changes in natural gas prices affect TNC's
fuel expense; however, they generally did not impact results of operations in
2001 due to fuel recovery mechanisms, which are no longer in place beginning
with deregulation in 2002.
The net decline in total Purchased Power expense in 2002 was mainly due to both
reduced MWHs purchased and reduced prices, partially offset by ICR adjustments
(see Note 6).
Other Operation expense decreased slightly in 2002 due to lower factoring and
transmission expenses, offset in part by a $1.4 million write-down of material
and supply inventory associated with the impaired plants.
As a result of TNC's recent ability to purchase electricity at a significantly
lower price than its current cost to generate electricity, TNC proposed in
September 2002 to "inactivate" various, high-cost gas fired generating
facilities. TNC recorded an impairment charge in the third quarter 2002 of
approximately $34.2 million related to these plants, which was recorded in Asset
Impairments expense. In the fourth quarter 2002, an additional asset impairments
charge of $3.9 million was also recorded in connection with these plants, along
with a $4.7 million charge for a wind-powered generation facility (see Note 13).
Additionally, a $1.2 million charge associated with fuel inventory (recorded in
Fuel) and a $1.4 million charge associated with materials and supplies (recorded
in Other Operations) was recorded in the fourth quarter of 2002 related to the
"inactivated" plants.
Depreciation and Amortization expense decreased due to the elimination in 2002
of excess earnings expense under Texas Restructuring Legislation and the
elimination of regulatory asset amortization that ended in 2001.
The decrease in Taxes Other Than Income Taxes is primarily a result of one time
2001 assessments and a decrease in the gross receipts tax due to deregulation.
The decrease in Income Taxes is primarily a result of a decrease in pre-tax
income resulting from the impairment of various generating facilities.
Other Changes
Nonoperating Income and Nonoperating Expenses increased significantly as a
result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties, offset in part by decreased
interest income. The revenues associated with the aforementioned energy related
construction projects included in Nonoperating Income increased $45.5 million in
2002. The expenses associated with these projects included in Nonoperating
Expenses increased $43.0 million in 2002.
Interest Charges declined primarily due to lower interest rates.
AEP TEXAS NORTH COMPANY
Statements of Operations
- ------------------------
Year Ended December 31,
-------------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $136,962 $368,741 $376,206
Energy Delivery 73,353 169,036 176,204
Sales to AEP Affiliates 240,425 18,681 18,654
-------- -------- --------
TOTAL OPERATING REVENUES 450,740 556,458 571,064
-------- -------- --------
OPERATING EXPENSES:
Fuel 100,466 177,140 183,154
Purchased Power:
Wholesale Electricity 80,391 70,395 68,080
AEP Affiliates 37,582 56,656 57,773
Other Operation 104,960 111,248 93,078
Asset Impairments 42,898 - -
Maintenance 22,295 22,343 21,241
Depreciation and Amortization 43,620 50,705 55,172
Taxes Other Than Income Taxes 22,471 28,319 25,321
Income Tax Expense (Credit) (11,814) 6,262 14,904
-------- -------- --------
TOTAL OPERATING EXPENSES 442,869 523,068 518,723
-------- -------- --------
OPERATING INCOME 7,871 33,390 52,341
NONOPERATING INCOME 53,763 12,199 9,530
NONOPERATING EXPENSES 54,755 10,695 12,664
NONOPERATING INCOME TAX CREDIT (289) (691) (1,459)
INTEREST CHARGES 20,845 23,275 23,216
-------- -------- --------
NET INCOME (LOSS) (13,677) 12,310 27,450
PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104
-------- -------- --------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(13,781) $ 12,206 $ 27,346
======== ======== ========
Statements of Comprehensive Income
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
NET INCOME (LOSS) $(13,677) $12,310 $27,450
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (15) - -
Minimum Pension Liability (30,748) - -
-------- ------- -------
COMPREHENSIVE INCOME (LOSS) $(44,440) $12,310 $27,450
======== ======= =======
The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes
to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
Statements of Retained Earnings
- -------------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $105,970 $122,588 $113,242
NET INCOME (LOSS) (13,677) 12,310 27,450
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,247 28,824 18,000
Preferred Stock 104 104 104
-------- -------- --------
BALANCE AT END OF PERIOD $ 71,942 $105,970 $122,588
======== ======== ========
The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes
to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
Balance Sheets
- --------------
December 31,
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 353,087 $ 443,508
Transmission 254,483 250,023
Distribution 445,486 431,969
General 111,679 112,797
Construction Work in Progress 37,012 22,575
---------- ----------
Total Electric Utility Plant 1,201,747 1,260,872
Accumulated Depreciation and Amortization 521,792 546,162
---------- ----------
NET ELECTRIC UTILITY PLANT 679,955 714,710
---------- ----------
OTHER PROPERTY AND INVESTMENTS 1,213 24,933
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,248 8,327
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,219 2,454
Accounts Receivable:
Customers 62,660 18,720
Affiliated Companies 43,632 8,656
Allowance for Uncollectible Accounts (5,041) (196)
Fuel Inventory 12,677 8,307
Materials and Supplies 9,574 11,190
Accrued Utility Revenues 6,829 -
Energy Trading and Derivative Contracts 4,130 10,240
Prepayments and Other 1,070 966
---------- ----------
TOTAL CURRENT ASSETS 136,750 60,337
---------- ----------
REGULATORY ASSETS 45,097 54,122
---------- ----------
DEFERRED CHARGES 11,912 2,446
---------- ----------
TOTAL ASSETS $ 877,175 $ 864,875
========== ==========
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
December 31,
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Accumulated Other Comprehensive Income (Loss) (30,763) -
Retained Earnings 71,942 105,970
-------- --------
Total Common Shareholder's Equity 180,744 245,535
Cumulative Preferred Stock
Not Subject to Mandatory Redemption 2,367 2,367
Long-term Debt 132,500 220,967
-------- --------
TOTAL CAPITALIZATION 315,611 468,869
-------- --------
OTHER NONCURRENT LIABILITIES 28,861 6,296
-------- --------
CURRENT LIABILITIES:
Short-term Debt - Affiliates 125,000 -
Long-term Debt Due Within One Year - 35,000
Advances from Affiliates 80,407 50,448
Accounts Payable - General 32,714 33,782
Accounts Payable - Affiliated Companies 76,217 11,388
Customer Deposits 117 4,191
Taxes Accrued 3,697 17,358
Interest Accrued 2,776 4,762
Energy Trading and Derivative Contracts 3,801 12,402
Other 17,414 9,824
-------- --------
TOTAL CURRENT LIABILITIES 342,143 179,155
-------- --------
DEFERRED INCOME TAXES 117,521 145,049
-------- --------
DEFERRED INVESTMENT TAX CREDITS 21,510 22,781
-------- --------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 557 5,250
-------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 50,972 37,475
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $877,175 $864,875
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
Statements of Cash Flows
------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $(13,677) $ 12,310 $ 27,450
Adjustments to Reconcile Net Income to Net Cash Flows From Operating
Activities:
Depreciation and Amortization 43,620 50,705 55,172
Writedown of Utility Assets 38,154 -
Writedown of Wind Farm Assets 4,744 - -
Deferred Income Taxes (12,275) (11,891) 8,164
Deferred Investment Tax Credits (1,271) (1,271) (1,271)
Mark-to-Market Energy Trading and Derivative Contracts (1,127) (3,506) 2,590
CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES:
Accounts Receivable (net) (74,071) 24,844 (1,445)
Fuel, Materials and Supplies (2,754) 3,187 8,478
Accrued Utility Revenues (6,829) - -
Accounts Payable 63,761 (42,604) 28,393
Taxes Accrued (13,661) (1,543) 6,443
Fuel Recovery 14,169 32,505 (53,841)
Transmission Coordination Agreement Settlement - - 15,465
Change in Other Assets (16,928) (1,432) 2,549
Change in Other Liabilities 16,514 11,056 (3,869)
-------- -------- --------
Net Cash Flows From Operating Activities 38,369 72,360 94,278
-------- -------- --------
INVESTING ACTIVITIES:
Construction Expenditures (43,563) (39,662) (64,477)
Sales Proceeds and Other 150 (127) -
-------- -------- --------
Net Cash Used For Investing Activities (43,413) (39,789) (64,477)
-------- -------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (130,799) - (48,000)
Change in Short-term Debt Affiliated (net) 125,000 - -
Change in Advances from Affiliates (net) 29,959 (8,130) 37,170
Dividends Paid on Common Stock (20,247) (28,824) (18,000)
Dividends Paid on Cumulative Preferred Stock (104) (104) (104)
-------- -------- --------
Net Cash Flows From (Used For) Financing Activities 3,809 (37,058) (28,934)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (1,235) (4,487) 867
Cash and Cash Equivalents at Beginning of Period 2,454 6,941 6,074
-------- -------- --------
Cash and Cash Equivalents at End of Period $ 1,219 $2,454 $6,941
======== ====== ======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $19,934,000
$19,279,000 and $19,088,000 and for income taxes was $15,544,000, $21,997,000
and ($906,000) in 2002, 2001 and 2000 respectively.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
Statements of Capitalization
- ----------------------------
December 31,
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $180,744 $245,535
-------- --------
PREFERRED STOCK: $100 par value - authorized shares 810,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
- ------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption:
4.40% $107 - - 1 23,672 2,367 2,367
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 88,190 211,657
Installment Purchase Contracts 44,310 44,310
Less Portion Due Within One Year - (35,000)
-------- --------
Long-term Debt Excluding Portion Due Within One Year 132,500 220,967
-------- --------
TOTAL CAPITALIZATION $315,611 $468,869
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6-7/8 2002 - October 1 $ - $ 35,000
7 2004 - October 1 18,469 40,000
6-1/8 2004 - February 1 24,036 40,000
6-3/8 2005 - October 1 37,609 72,000
7-3/4 2007 - June 1 8,151 25,000
Unamortized Discount (75) (343)
------- --------
$88,190 $211,657
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
Red River Authority
of Texas:
6.00 2020 - June 1 $44,310 $44,310
======= =======
Under the terms of the installment purchase contracts, TNC is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ -
2004 42,505
2005 37,609
2006 -
2007 8,151
Later Years 44,310
--------
Principal Amount 132,575
Less: Unamortized Discount (75)
--------
Total $132,500
AEP TEXAS NORTH COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------
The notes to TNC's financial statements are combined with the notes to financial
statements for AEP and its other subsidiary registrants. Listed below are the
combined notes that apply to TNC. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Asset Imapairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of AEP Texas North Company:
We have audited the accompanying balance sheets and statements of capitalization
of AEP Texas North Company as of December 31, 2002 and 2001, and the related
statements of operations, retained earnings, comprehensive income, and cash
flows for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of AEP Texas North Company as of December 31,
2002 and 2001, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
Year Ended December 31,
-----------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,814,470 $1,784,259 $1,759,253 $1,586,050 $1,672,244
Operating Expenses 1,512,407 1,509,273 1,558,099 1,344,814 1,443,701
---------- ---------- ---------- ---------- ----------
Operating Income 302,063 274,986 201,154 241,236 228,543
Nonoperating Items,
Net 20,106 6,868 11,752 8,096 (8,301)
Interest Charges 116,677 120,036 148,000 128,840 126,912
---------- ---------- ---------- ---------- -----------
Income Before
Extraordinary Item 205,492 161,818 64,906 120,492 93,330
Extraordinary Gain - - 8,938 - -
---------- ---------- ---------- ---------- ----------
Net Income 205,492 161,818 73,844 120,492 93,330
Preferred Stock
Dividend Requirements 2,897 2,011 2,504 2,706 2,497
---------- ---------- ---------- ---------- ----------
Earnings Applicable
to Common Stock $ 202,595 $ 159,807 $ 71,340 $ 117,786 $ 90,833
=========== ========== ========== ========== ==========
December 31,
------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,895,303 $5,664,657 $5,418,278 $5,262,951 $5,087,359
Accumulated
Depreciation and
Amortization 2,424,607 2,296,481 2,188,796 2,079,490 1,984,856
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $3,470,696 $3,368,176 $3,229,482 $3,183,461 $3,102,503
========== ========== ========== ========== ==========
Total Assets $4,627,847 $4,482,785 $6,572,595 $4,352,219 $4,047,038
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $977,700 $976,244 $975,676 $974,717 $924,091
Accumulated Other
Comprehensive Income
(Loss) (72,082) (340) - - -
Retained Earnings 260,439 150,797 120,584 175,854 179,461
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,166,057 $1,126,701 $1,096,260 $1,150,571 $1,103,552
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 17,790 $ 17,790 $ 17,790 $ 18,491 $ 19,359
Subject to Mandatory
Redemption 10,860 10,860 10,860 20,310 22,310
---------- ---------- ---------- ---------- -----------
Total Cumulative
Preferred Stock $ 28,650 $ 28,650 $ 28,650 $ 38,801 $ 41,669
======== ========== ========== ========== ==========
Long-term Debt (a) $1,893,861 $1,556,559 $1,605,818 $1,665,307 $1,552,455
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 33,589 $ 46,285 $ 63,160 $ 64,645 $ 65,175
========== ========== ======== ========== ==========
Total Capitalization
And Liabilities $4,627,847 $4,482,785 $6,572,595 $4,352,219 $4,047,038
========== ========== ========== ========== ==========
(a) Including portion due within one year.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operation
------------------------------------------------------------
APCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 925,000 retail customers in southwestern
Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool,
shares in the revenues and costs of the AEP Power Pool's wholesale sales to
neighboring utility systems and power marketers including power trading
transactions. APCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of revenues and costs.
Results of Operations
- ---------------------
Net Income increased $44 million or 27% in 2002 due to higher retail sales
resulting from increased generation, weather related electricity demands and
reductions in Maintenance expense. Most significantly, the Mountainer, Amos and
Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002
resulting in increased availability of generation and decreased maintenance
expense. In addition, Nonoperating Income less Nonoperating Expenses increased
$10 million as a result of a reduction in trading incentive compensation
recorded in Nonoperating Expenses offset in part by decreased power trading
gains recorded in Nonoperating Income.
Net Income increased $88 million or 119% in 2001 primarily due to the effect of
a court decision related to a corporate owned life insurance (COLI) program
recorded in 2000. In February 2001, the U.S. District Court for the Southern
District of Ohio ruled against AEP and certain of its subsidiaries, including
APCo, in a suit over deductibility of interest claimed in AEP's consolidated tax
return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and
interest attributable to the COLI interest deductions for taxable years 1991-98.
Also contributing to the increase in net income was growth in and strong
performance by the wholesale electricity business in the first half of 2001
offset in part by the effect of extremely mild weather in November and December
combined with weak economic conditions which reduced retail energy sales.
Operating Revenues
- ------------------
Operating Revenues increased $30 million or 2% in 2002 as a result of weather
related demand and increased generation resulting from availablility of plants
previously down for maintenance coming back online. An increase of $25 million,
or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power
Pool transactions. Changes in components of revenues were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2002 2001
---------------------------
Amount % Amount %
------ - ------ -
Wholesale
Electricity* $16.0 2 $(11.7) (1)
Energy Delivery* (1.0) - 20.1 3
Sales to AEP
Affiliates 15.2 9 16.6 11
----- ------
Total
Revenues $30.2 2 $ 25.0 1
===== ======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Operating Revenues for 2002 increased as a result of an increase in generation
and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in
residential and commercial sales due to warmer weather during July and
September. Sales to AEP affiliates increased for the year due to an increase in
generation capacity and power available to be delivered to AEP Power Pool. These
increases were partially offset by flat industrial sales as recessionary
conditions continued into 2002.
The year 2001 saw a decrease in kilowatt hour sales to industrial customers.
This decrease was due to the economic recession. In the fourth quarter, sales to
residential and commercial customers declined, reflecting recession-related
reductions in demand.
The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP
Power Pool transactions. As the quantity of energy sold by the AEP Power Pool
rose, APCo's contribution of energy to the Pool rose, accounting for the
increase in APCo's revenues from Sales to AEP Affiliates.
Operating Expenses
- ------------------
Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel
and Wholesale Electricity Purchased Power expenses were offset by decreases in
power purchases from AEP Affiliates due to increases in APCo generation and
availability as plants previously down for maintenance resumed operations. The
decrease in operating expenses in 2001 of 3% is due to decreases in income
taxes, other operation expense, fuel expense and taxes other than income taxes
partially offset by increases in electricity purchased power expense and
depreciation and amortization expenses. Changes in the components of Operating
Expenses are as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2002 2001
-----------------------------
Amount % Amount %
------ - ------ -
Fuel $ 79.4 23 $ (17.6) (5)
Wholesale
Electricity
Purchases 15.0 36 17.4 70
AEP Affiliate
Purchases (112.3) (32) (8.9) (3)
Other Operation 8.9 3 (18.6) (7)
Maintenance (10.2) (8) 7.9 6
Depreciation and
Amortization 8.9 5 17.3 11
Taxes Other Than
Income Taxes (4.6) (5) (11.8) (11)
Income Taxes 18.0 19 (34.5) (27)
------- --------
Total $ 3.1 - $ (48.8) (3)
======= ========
Fuel expense increased for 2002 as a result of an increase in APCo generation.
Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in
2001 which resulted in increased availability in 2002. The decrease in Fuel
expense in 2001 is due to a decline in generation as a result of scheduled plant
maintenance.
Wholesale Electricity Purchases increased for 2002 as a result of increased
purchases from third parties for resale to wholesale customers and to meet
internal demand. Electricity purchased power expense increased in 2001 due to
increases in wholesale electricity prices and as a result of the previously
mentioned plant outages.
The decrease for 2002 in Purchases from AEP Affiliates is a result of increased
internal generation due to plant availability. Purchased power from AEP
affiliates decreased in 2001 as the result of a decrease in AEP Power Pool
capacity charges due to a reduction in APCo's MLR.
Other Operation expense increased in 2002 mainly due to severance expenses
related to the sustained earnings initiative plan, a reduction in the gains
recorded on the dispositions of SO2 emission allowances, and increased insurance
premiums and other employee benefit costs. These increases were offset by
reduced trading overhead expenses as a result of reduced staffing and weaker
market conditions; a decrease in transmission equalization charges caused by a
reduction in APCo's MLR ratio; and energy delivery severance accruals recorded
in 2001 for which there was no comparable activity in 2002. Other operation
expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for
the disallowance of the COLI program interest deduction. Additionally, the
decrease was the result of a gain recorded on the disposition of SO2 emission
allowances offset in part by increased wholesale power trading incentive
compensation expense.
The decrease in Maintenance expense in 2002 is primarily due to previously
discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in
the year 2001.
Depreciation and Amortization expense increased during 2002 due to increased
amortization for the net generation-related regulatory assets related to the
Company's West Virginia jurisdiction which were assigned to the distribution
portion of the Company's business and are being recovered through regulated
rates. Investment in production plant in service, primarily equipment related to
emission control, contributed to the increase in depreciation and amortization
expense.
Depreciation and Amortization expense increased in 2001 due to accelerated
amortization, beginning in July 2000, of the transition regulatory assets in the
Virginia and West Virginia jurisdictions. Additional investments in distribution
and transmission plant also contributed to the increases in depreciation and
amortization expense in 2001. During June 2000 we discontinued the application
of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net
generation-related regulatory assets were assigned to the energy delivery
business's regulated distribution business where the Virginia and West Virginia
jurisdictions authorized the recovery of these transition regulatory assets
through regulated rates.
The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily
to a decrease in municipal license tax. The municipal license tax was replaced
by the Virginia consumption tax. The municipal license tax was imposed on APCo
and the Virginia consumption tax is imposed on the customer with APCo acting as
collector agent. The decrease in Taxes Other Than Income Taxes in 2001 is due to
the elimination of the Virginia gross receipts tax as a result of a tax law
change due to deregulation in that state.
The increase in Income Taxes for 2002 was due to an increase in pre-tax income.
Income taxes attributable to operations decreased in 2001 due to the effect of
the disallowance of COLI interest deductions in 2000 offset in part by an
increase in pre-tax operating income.
Nonoperating Income and Nonoperating Expenses
- ---------------------------------------------
The Nonoperating Income decrease for 2002 was due primarily to a decrease in net
power trading gains driven by a decline in market prices. Nonoperating Expenses
decreased as a result of decreased trading incentives. The increase in
Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable
increases in the level of activity in the wholesale business's trading
transactions outside of the AEP System's traditional marketing area.
Interest Charges
- ----------------
Interest Charges for 2002 decreased primarily as a result of lower AEP money
pool balances and interest rates and the retirement of first mortgage bonds in
2001. Interest charges decreased in 2001 primarily due to the effect of
recognizing in 2000 previously deferred interest payments to the IRS related to
the COLI disallowances and interest on resultant state income tax deficiencies.
Additionally, the decrease in 2001 is due to the retirement of first mortgage
bonds in 2000.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $1,033,904 $1,017,938 $1,029,657
Energy Delivery 594,089 595,036 574,918
Sales to AEP Affiliates 186,477 171,285 154,678
---------- ---------- ----------
Total Operating Revenues 1,814,470 1,784,259 1,759,253
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 430,963 351,557 369,161
Purchased Power:
Wholesale Electricity 57,091 42,092 24,720
AEP Affiliates 234,597 346,878 355,774
Other Operation 269,426 260,518 279,114
Maintenance 122,209 132,373 124,493
Depreciation and Amortization 189,335 180,393 163,089
Taxes Other Than Income Taxes 95,249 99,878 111,692
Income Taxes 113,537 95,584 130,056
---------- ---------- ----------
Total Operating Expenses 1,512,407 1,509,273 1,558,099
---------- ---------- ----------
OPERATING INCOME 302,063 274,986 201,154
NONOPERATING INCOME 29,278 49,507 31,204
NONOPERATING EXPENSES 11,783 41,500 16,329
NONOPERATING INCOME TAX EXPENSE (BENEFIT) (2,611) 1,139 3,123
INTEREST CHARGES 116,677 120,036 148,000
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 205,492 161,818 64,906
EXTRAORDINARY GAIN - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(Inclusive of Tax Benefit of $7,872,000) - - 8,938
---------- ---------- ----------
NET INCOME 205,492 161,818 73,844
PREFERRED STOCK DIVIDEND REQUIREMENTS 2,897 2,011 2,504
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $202,595 $159,807 $ 71,340
======== ======== ========
Consolidated Statements of Comprehensive Income
Year Ended December 31,
------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $205,492 $161,818 $73,844
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (1,580) (340) -
Minimum Pension Liability (70,162) - -
-------- -------- -------
COMPREHENSIVE INCOME $133,750 $161,478 $73,844
======== ======== =======
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $150,797 $120,584 $175,854
Net Income 205,492 161,818 73,844
-------- -------- --------
356,289 282,402 249,698
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 92,952 129,594 126,612
Cumulative Preferred Stock:
4-1/2% Series 801 801 811
5.90% Series 278 278 307
5.92% Series 364 364 364
6.85% Series - - 289
-------- -------- --------
Total Cash Dividends Declared 94,395 131,037 128,383
Capital Stock Expense 1,455 568 731
-------- -------- --------
Total Deductions 95,850 131,605 129,114
-------- -------- --------
Retained Earnings December 31 $260,439 $150,797 $120,584
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------
December 31,
------------------------------
2002 2001
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,245,945 $2,093,532
Transmission 1,218,108 1,222,226
Distribution 1,951,804 1,887,020
General 272,901 257,957
Construction Work in Progress 206,545 203,922
---------- ----------
Total Electric Utility Plant 5,895,303 5,664,657
Accumulated Depreciation and Amortization 2,424,607 2,296,481
---------- ----------
NET ELECTRIC UTILITY PLANT 3,470,696 3,368,176
---------- ----------
OTHER PROPERTY AND INVESTMENTS 54,653 53,736
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 115,748 119,638
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 4,285 13,663
Accounts Receivable:
Customers 132,266 113,371
Affiliated Companies 122,665 63,368
Miscellaneous 28,629 11,847
Allowance for Uncollectible Accounts (13,439) (1,877)
Fuel Inventory 53,646 56,699
Materials and Supplies 59,886 59,849
Accrued Utility Revenues 30,948 30,907
Energy Trading and Derivative Contracts 94,238 137,742
Prepayments and Other 13,396 16,018
---------- ----------
TOTAL CURRENT ASSETS 526,520 501,587
---------- ----------
REGULATORY ASSETS 395,553 397,383
---------- ----------
DEFERRED CHARGES 64,677 42,265
---------- ----------
TOTAL ASSETS $4,627,847 $4,482,785
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
December 31,
-------------------------------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 717,242 715,786
Accumulated Other Comprehensive Income (Loss) (72,082) (340)
Retained Earnings 260,439 150,797
---------- ----------
Total Common Shareowner's Equity 1,166,057 1,126,701
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,738,854 1,476,552
---------- ----------
TOTAL CAPITALIZATION 2,933,561 2,631,903
---------- ----------
OTHER NONCURRENT LIABILITIES 173,438 84,104
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,007 80,007
Advances From Affiliates 39,205 291,817
Accounts Payable - General 141,546 127,597
Accounts Payable - Affiliated Companies 98,374 84,518
Taxes Accrued 29,181 55,583
Customer Deposits 26,186 13,177
Interest Accrued 22,437 21,770
Energy Trading and Derivative Contracts 69,001 121,161
Other 79,832 79,089
---------- ----------
Total CURRENT LIABILITIES 660,769 874,719
---------- ----------
DEFERRED INCOME TAXES 701,801 703,575
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 33,691 38,328
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 44,517 60,518
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 80,070 89,638
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,627,847 $4,482,785
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 205,492 $ 161,818 $73,844
Adjustments for Noncash Items:
Depreciation and Amortization 189,335 180,505 163,202
Deferred Income Taxes 16,777 42,498 8,602
Deferred Investment Tax Credits (4,637) (4,765) (4,915)
Deferred Power Supply Costs (net) 6,365 1,411 (84,408)
Mark-to-Market of Energy Trading Contracts (21,151) (68,254) (1,843)
Provision for Rate Refunds - - (4,818)
Extraordinary Gain - - (8,938)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (83,412) 134,099 (166,911)
Fuel, Materials and Supplies 3,016 (19,957) 18,487
Accrued Utility Revenues (41) 35,592 (13,081)
Accounts Payable 27,805 (45,073) 159,369
Taxes Accrued (26,402) (7,675) 14,220
Revenue Refunds Accrued - - 181
Incentive Plan Accrued (858) (2,451) 10,662
Disputed Tax and Interest Related to COLI - - 72,440
Change in Operating Reserves (3,190) (5,358) (19,770)
Rate Stabilization Deferral - - 75,601
Change in Other Assets (43,337) 19,418 (13,021)
Change in Other Liabilities 14,948 (27,954) 9,817
--------- --------- ---------
Net Cash Flows From Operating Activities 280,710 393,854 288,720
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (276,549) (306,046) (199,285)
Proceeds From Sales of Property and Other 1,074 1,182 159
Net Cost of Removal and Other - (8,434) (7,500)
--------- --------- ---------
Net Cash Flows Used For Investing
Activities (275,475) (313,298) (206,626)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 647,401 124,588 74,788
Retirement of Cumulative Preferred Stock - - (9,924)
Retirement of Long-term Debt (315,007) (175,000) (136,166)
Change in Short-term Debt (net) - (191,495) 68,015
Change in Advances From Affiliates (252,612) 300,204 (8,387)
Dividends Paid on Common Stock (92,952) (129,594) (126,612)
Dividends Paid on Cumulative Preferred Stock (1,443) (1,443) (1,938)
--------- --------- ---------
Net Cash Flows Used For
Financing Activities (14,613) (72,740) (140,224)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (9,378) 7,816 (58,130)
Cash and Cash Equivalents January 1 13,663 5,847 63,977
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 4,285 $13,663 $ 5,847
========= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000
and $124,579,000 and for income taxes was $125,120,000, $56,981,000 and
$63,682,000 in 2002, 2001 and 2000, respectively. There were no noncash
acquisitions under capital leases in 2002. In 2001 and 2000, non cash
acquisitions under capital leases were $2,510,000 and $14,116,000, respectively.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,166,057 $1,126,701
---------- ----------
PREFERRED STOCK: No par value - authorized shares 8,000,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 (a) Year Ended December 31, December 31, 2002
- ------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption (b):
4-1/2% $110 6 - 7,011 177,899 17,790 17,790
---------- ----------
Subject to Mandatory Redemption (b):
5.90% (c) - - 10,000 47,100 4,710 4,710
5.92% (c) - - - 61,500 6,150 6,150
---------- ----------
10,860 10,860
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 489,697 639,365
Installment Purchase Contracts 235,027 234,904
Senior Unsecured Notes 1,166,609 518,247
Junior Debentures - 161,507
Other Long-term Debt 2,528 2,536
Less Portion Due Within One Year (155,007) (80,007)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,738,854 1,476,552
---------- ----------
TOTAL CAPITALIZATION $2,933,561 $2,631,903
========== ==========
(a) The cumulative preferred stock is callable at the price indicated plus
accrued dividends. The involuntary liquidation preference is $100 per
share. The aggregate involuntary liquidation price for all shares of
cumulative preferred stock may not exceed $300 million. The unissued shares
of the cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.
(b) The sinking fund provisions of each series subject to mandatory redemption
have been met by shares purchased in advance of the due date.
(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
series outstanding under sinking fund provisions at its option and all
outstanding shares must be redeemed in 2008. Shares previously redeemed may
be applied to meet the sinking fund requirement.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
7.38 2002 - August 15 $ - $ 50,000
7.40 2002 - December 1 - 30,000
6.65 2003 - May 1 - 40,000
6.85 2003 - June 1 - 30,000
6.00 2003 - November 1 30,000 30,000
7.70 2004 - September 1 21,000 21,000
7.85 2004 - November 1 50,000 50,000
8.00 2005 - May 1 50,000 50,000
6.89 2005 - June 22 30,000 30,000
6.80 2006 - March 1 100,000 100,000
8.50 2022 - December 1 70,000 70,000
7.80 2023 - May 1 30,237 30,237
7.15 2023 - November 1 20,000 20,000
7.125 2024 - May 1 45,000 45,000
8.00 2025 - June 1 45,000 45,000
Unamortized Discount (1,540) (1,872)
-------- --------
Total $489,697 $639,365
======== ========
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds, by governmental authorities as
follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
Industrial Development
Authority of
Russell County, Virginia:
7.70 2007 - November 1 $ 17,500 $ 17,500
5.00 2021 - November 1 19,500 19,500
Putnam County, West Virginia:
5.45 2019 - June 1 40,000 40,000
6.60 2019 - July 1 30,000 30,000
Mason County, West Virginia:
7-7/8 2013 - November 1 10,000 10,000
6.85 2022 - June 1 40,000 40,000
6.60 2022 - October 1 50,000 50,000
6.05 2024 - December 1 30,000 30,000
Unamortized Discount (1,973) (2,096)
-------- --------
Total $235,027 $234,904
======== ========
Under the terms of the installment purchase contracts, APCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
(a) 2003 - August 20 $ 125,000 $125,000
7.45 2004 - November 1 50,000 50,000
4.80 2005 - June 15 450,000 -
4.32 2007 - November 12 200,000 -
6.60 2009 - May 1 150,000 150,000
7.20 2038 - March 31 100,000 100,000
7.30 2038 - June 30 100,000 100,000
Unamortized Discount (8,391) (6,753)
Total $1,166,609 $518,247
========== ========
(a) A floating interest rate is determined monthly. The rate on December
31, 2002 and 2001 was 2.167% and 2.839%, respectively.
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
8-1/4% Series A due
2026 - September 30 $ - $ 75,000
8% Series B due 2027
- March 31 - 90,000
Unamortized Discount - (3,493)
-------- --------
Total $ - $161,507
======== ========
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 155,007
2004 121,008
2005 530,010
2006 100,011
2007 217,513
Later Years 782,216
----------
Total Principal Amount 1,905,765
Unamortized Discount (11,904)
----------
Total $1,893,861
==========
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------
The notes to APCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to APCo. The combined footnotes
begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investments Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments
and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Appalachian Power Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Appalachian Power Company and subsidiaries as of
December 31, 2002 and 2001, and the related consolidated statements of income,
comprehensive income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Appalachian Power Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,400,160 $1,350,319 $1,304,409 $1,190,997 $1,187,745
Operating Expenses 1,180,381 1,098,142 1,108,532 968,207 975,534
---------- ---------- ---------- ---------- ----------
Operating Income 219,779 252,177 195,877 222,790 212,211
Nonoperating Items,
Net 15,263 7,738 5,153 2,709 (1,343)
Interest Charges 53,869 68,015 80,828 75,229 77,824
---------- ---------- --------- ---------- ----------
Income Before
Extraordinary Item 181,173 191,900 120,202 150,270 133,044
Extraordinary Loss - (30,024) (25,236) - -
---------- ---------- --------- ---------- ----------
Net Income 181,173 161,876 94,966 150,270 133,044
Preferred Stock
Dividend
Requirements 1,332 1,095 1,783 2,131 2,131
---------- ---------- --------- ---------- ----------
Earnings Applicable to
Common Stock $179,841 $160,781 $93,183 $148,139 $130,913
======== ======== ======= ======== ========
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,467,626 $3,354,320 $3,266,794 $3,151,619 $3,053,565
Accumulated Depreciation 1,465,174 1,377,032 1,299,697 1,210,994 1,134,348
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $2,002,452 $1,977,288 $1,967,097 $1,940,625 $1,919,217
========== ========== ========== ========== ==========
Total Assets $2,753,240 $2,722,388 $3,877,491 $2,808,623 $2,681,690
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $616,410 $615,395 $614,380 $613,899 $613,518
Accumulated Other
Comprehensive Income
(Loss) (59,357) - - - -
Retained Earnings 290,611 176,103 99,069 246,584 186,441
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $847,664 $791,498 $713,449 $860,483 $799,959
======== ======== ======== ======== ========
Cumulative Preferred
Stock - Subject to
Mandatory
Redemption (a) $ - $ 10,000 $ 15,000 $ 25,000 $ 25,000
======== ======== ======== ======== ========
Long-term Debt (a) $621,626 $791,848 $899,615 $924,545 $959,786
======== ======== ======== ======== ========
Obligations Under
Capital Leases (a) $ 27,610 $ 34,887 $ 42,932 $ 40,270 $ 42,362
======== ======== ======== ======== ========
Total Capitalization and
Liabilities $2,753,240 $2,722,388 $3,877,491 $2,808,623 $2,681,690
========== ========== ========== ========== ==========
(a) Including portion due within one year.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------
Columbus Southern Power Company is a public utility engaged in the generation,
purchase, sale, transmission and distribution of electric power to 689,000
retail customers in central and southern Ohio. CSPCo as a member of the AEP
Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale
sales to neighboring utility systems and power marketers including power trading
transactions. CSPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
AEP Power Pool revenues and costs. The result of this calculation is the member
load ratio (MLR) which determines each companies percentage share of AEP Power
Pool revenues and costs.
Results of Operations
- ---------------------
Net Income increased $19 million or 12% in 2002 due to reduced interest charges
and a $30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio
excise taxes stranded by Ohio deregulation offset by higher operating expenses.
Operating Revenues
- ------------------
Operating Revenues increased in 2002 mainly as a result of increased residential
and commercial sales due to demand caused by weather conditions.
Changes in the components of Operating Revenues were:
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Retail* $51 8
Wholesale Marketing 3 2
Unrealized MTM (4) (22)
Other 1 3
---
Wholesale Electricity* 51 6
Energy Delivery* 9 2
Sales to AEP Affiliates (10) (15)
----
Total Revenues $50 4
===
* Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
During the summer months, cooling degree days increased 35%. For the fall
season, heating degree days increased 34%. This reflects a return to more normal
weather conditions since the weather experienced in 2001 was abnormally mild.
Operating Expenses
- ------------------
Operating Expenses increased in 2002 mainly as a result of purchased power,
operating expenses and state taxes.
Changes in the components of Operating Expenses were:
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Fuel $10 6
Wholesale Purchased Power 4 37
AEP Affiliates Purchased
Power 18 6
Other Operation Expenses 18 8
Maintenance Expense (2) (4)
Depreciation and
Amortization 4 3
Taxes Other Than
Income Taxes 25 22
Income Taxes 5 5
---
Total $82 7
===
Fuel cost increased as a result of a 10% increase in generation partially offset
by a slight cost decrease per ton of coal consumed.
Wholesale Purchased Power increased in 2002 due to increased purchases from
third parties for resale to wholesale customers and to meet internal demand.
Expenses related to AEP Affiliates Purchased Power increased due to greater
system pool capacity charges.
The increase in Other Operation expenses was attributable to a number of
factors: higher OPEB post retirement costs as a result of higher medical cost
and lower investment performance, 2002 Sustained Earnings Initiative Expenses,
and the 2001 reversal of a quality of service liability accrual. The increase
was partially offset by a reduction in energy trading overheads reflecting
reduced marketing activity.
The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in
property taxes and a full year of the state excise tax which replaced the state
gross receipts tax during 2001.
The increase in Income Taxes is predominately due to an increase in state taxes
as a result of the State of Ohio's tax legislation resulting from utility
deregulation. This increase was offset in part by a decrease in federal taxes
due to a decrease in pre-tax operating income.
Nonoperating Income and Nonoperating Expense
- --------------------------------------------
The decrease in Nonoperating Income in 2002 is due to a reduction in net gains
from AEP Power Pool trading transactions outside of the AEP System's traditional
marketing area. The AEP Power Pool enters into power trading transactions for
the purchase and sale of electricity and for options, futures and swaps. CSPCo's
share of the AEP Power Pool's gains and losses from forward electricity trading
transactions outside of the AEP System traditional marketing area and for
speculative financial transactions (options, futures, swaps) is included in
Nonoperating Income. The decrease reflects a reduction in electricity prices and
margins due to a decrease in demand.
The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy
trading incentive compensation.
Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax
nonoperating income.
Interest Charges
- ----------------
Interest Charges decreased in 2002 primarily due to a decrease in the
outstanding balance of long-term debt since the first quarter of 2001, the
refinancing of debt at favorable interest rates and a reduction in short-term
interest rates.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
OPERATING REVENUES:
Wholesale Electricity $ 850,680 $ 799,589 $ 856,998
Energy Delivery 492,278 483,219 398,046
Sales to AEP Affiliates 57,202 67,511 49,365
---------- ---------- ----------
Total Operating Revenues 1,400,160 1,350,319 1,304,409
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 185,086 175,153 189,155
Purchased Power:
Wholesale Electricity 15,023 10,957 9,879
AEP Affiliates 310,605 292,199 287,750
Other Operation 237,802 219,497 219,840
Maintenance 60,003 62,454 69,676
Depreciation and Amortization 131,624 127,364 99,640
Taxes Other Than Income Taxes 136,024 111,481 123,223
Income Taxes 104,214 99,037 109,369
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,180,381 1,098,142 1,108,532
---------- ---------- ----------
OPERATING INCOME 219,779 252,177 195,877
NONOPERATING INCOME 26,360 32,756 20,580
NONOPERATING EXPENSES 4,308 21,095 8,070
NONOPERATING INCOME TAX EXPENSE 6,789 3,923 7,357
INTEREST CHARGES 53,869 68,015 80,828
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 181,173 191,900 120,202
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION - Net of
tax (Note 2) - (30,024) (25,236)
---------- ---------- ----------
NET INCOME 181,173 161,876 94,966
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,332 1,095 1,783
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $179,841 $160,781 $ 93,183
======== ======== ========
Consolidated Statements of Comprehensive Income
- -----------------------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
NET INCOME $181,173 $161,876 $94,966
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (267) - -
Minimum Pension Liability (59,090) - -
-------- -------- -------
COMPREHENSIVE INCOME $121,816 $161,876 $94,966
======== ======== =======
The common stock of the CSPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------
Year Ended December 31,
--------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $176,103 $ 99,069 $246,584
Net Income 181,173 161,876 94,966
-------- -------- --------
357,276 260,945 341,550
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 65,300 82,952 240,600
Cumulative Preferred Stock - 7% Series 350 875 1,400
-------- -------- --------
Total Cash Dividends Declared 65,650 83,827 242,000
Capital Stock Expense 1,015 1,015 481
-------- -------- --------
Total Deductions 66,665 84,842 242,481
-------- -------- --------
Retained Earnings December 31 $290,611 $176,103 $ 99,069
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,582,627 $1,574,506
Transmission 413,286 401,405
Distribution 1,208,255 1,159,105
General 165,025 146,732
Construction Work in Progress 98,433 72,572
---------- ----------
Total Electric Utility Plant 3,467,626 3,354,320
Accumulated Depreciation 1,465,174 1,377,032
---------- ----------
NET ELECTRIC UTILITY PLANT 2,002,452 1,977,288
---------- ----------
OTHER PROPERTY AND INVESTMENTS 35,759 40,369
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 77,810 73,310
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,479 12,358
Advances to Affiliates 31,257 -
Accounts Receivable:
Customers 49,566 41,770
Affiliated Companies 54,518 63,470
Miscellaneous 22,005 16,968
Allowance for Uncollectible Accounts (634) (745)
Fuel 24,844 20,019
Materials and Supplies 40,339 38,984
Accrued Utility Revenues 12,671 7,087
Energy Trading Contracts 63,348 84,323
Prepayments and Other Current Assets 7,308 28,733
---------- ----------
TOTAL CURRENT ASSETS 306,701 312,967
---------- ----------
REGULATORY ASSETS 257,682 262,267
---------- ----------
DEFERRED CHARGES 72,836 56,187
---------- ----------
TOTAL ASSETS $2,753,240 $2,722,388
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 575,384 574,369
Accumulated Other Comprehensive Income (Loss) (59,357) -
Retained Earnings 290,611 176,103
---------- ----------
Total Common Shareholder's Equity 847,664 791,498
Cumulative Preferred Stock - Subject to
Mandatory Redemption - 10,000
Long-term Debt - General 418,626 571,348
Long term Debt - Affiliated Companies 160,000 -
---------- ----------
TOTAL CAPITALIZATION 1,426,290 1,372,846
---------- ----------
OTHER NONCURRENT LIABILITIES 95,460 36,715
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 43,000 20,500
Long-term Debt Due Within One Year - Affiliated Companies - 200,000
Short-term Debt - Affiliated Companies 290,000 -
Advances from Affiliates - 181,384
Accounts Payable - General 89,736 60,689
Accounts Payable - Affiliated Companies 81,599 83,697
Taxes Accrued 112,172 116,364
Interest Accrued 9,798 10,907
Energy Trading Contracts 46,375 72,082
Other 36,790 36,305
---------- ----------
TOTAL CURRENT LIABILITIES 709,470 781,928
---------- ----------
DEFERRED INCOME TAXES 437,771 443,722
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 33,907 37,176
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 29,926 37,101
---------- ----------
DEFERRED CREDITS 20,416 12,900
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $2,753,240 $2,722,388
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 181,173 $ 161,876 $ 94,966
Adjustments for Noncash Items:
Depreciation and Amortization 131,753 128,500 100,182
Deferred Income Taxes 23,292 24,108 (4,063)
Deferred Investment Tax Credits (3,269) (4,058) (3,482)
Deferred Fuel Costs (net) - - 5,352
Mark to Market of Energy Trading Contracts (16,667) (44,680) (3,393)
Extraordinary Loss - 30,024 25,236
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (3,992) 19,987 (29,737)
Fuel, Materials and Supplies (6,180) (7,780) 11,957
Accrued Utility Revenues (5,584) 2,551 38,479
Accounts Payable 26,949 (16,249) 81,284
Disputed Tax and Interest Related to COLI - - 39,483
Change in Other Assets (8,027) (42,066) (121,115)
Change in Other Liabilities (22,448) (18,769) 132,441
--------- --------- ---------
Net Cash Flows From Operating Activities 297,000 233,444 367,590
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (136,800) (132,532) (127,987)
Proceeds From Sales and Leaseback
Transactions and Other 730 10,841 1,560
--------- --------- ---------
Net Cash Flows Used For Investing
Activities (136,070) (121,691) (126,427)
--------- --------- ---------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (212,641) 92,652 88,732
Issuance of Affiliated Long-term Debt 160,000 200,000 -
Retirement of Preferred Stock (10,000) (5,000) (10,000)
Retirement of General Long-term Debt (133,343) (314,733) (25,274)
Retirement of Affiliated Long-term Debt (200,000) - -
Change in Short-term Debt (net) 290,000 - (45,500)
Dividends Paid on Common Stock (65,300) (82,952) (240,600)
Dividends Paid on Cumulative Preferred Stock (525) (962) (1,575)
--------- --------- ---------
Net Cash Flows Used For
Financing Activities (171,809) (110,995) (234,217)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (10,879) 758 6,946
Cash and Cash Equivalents January 1 12,358 11,600 4,654
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 1,479 $ 12,358 $ 11,600
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000
and $68,506,000 and for income taxes was $117,591,000, 80,485,000 and
$81,109,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under
capital leases were $1,019,000 and $10,777,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------
December 31,
-----------
2002 2001
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 847,664 $ 791,498
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 2,500,000
$25 par value - authorized shares 7,000,000
Shares
Number of Shares Redeemed Outstanding
Series Year Ended December 31, December 31, 2002
- ------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Subject to Mandatory Redemption:
7.00% 100,000 50,000 100,000 - - 10,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 222,797 243,197
Installment Purchase Contracts 91,275 91,220
Senior Unsecured Notes 147,554 147,458
Notes - Affiliated 160,000 200,000
Junior Debentures - 109,973
Less Portion Due Within One Year ( 43,000) (220,500)
---------- ----------
Total Long-term Debt Excluding Portion Due Within One Year 578,626 571,348
---------- ----------
TOTAL CAPITALIZATION $1,426,290 $1,372,846
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
7.25 2002 - October 1 $ - $ 14,000
7.15 2002 - November 1 - 6,500
6.80 2003 - May 1 13,000 13,000
6.60 2003 - August 1 25,000 25,000
6.10 2003 - November 1 5,000 5,000
6.55 2004 - March 1 26,500 26,500
6.75 2004 - May 1 26,000 26,000
8.70 2022 - July 1 2,000 2,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 14,000 14,000
8.40 2022 - October 15 13,000 13,000
7.90 2023 - May 1 40,000 40,000
7.75 2023 - August 1 33,000 33,000
7.60 2024 - May 1 11,000 11,000
Unamortized Discount (703) (803)
-------- --------
Total $222,797 $243,197
======== ========
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by the Ohio Air Quality Development
Authority:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (970) (1,025)
------- -------
Total $91,275 $91,220
======= =======
Under the terms of the installment purchase contracts, CSPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at the Zimmer Plant.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ ------------------
6.85 2005 - October 3 $ 36,000 $ 36,000
6.51 2008 - February 1 52,000 52,000
6.55 2008 - June 26 60,000 60,000
Unamortized Discount (446) (542)
-------- --------
Total $147,554 $147,458
======== ========
Notes payable to parent company were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
(a) 2002 - Sept 25 $ - $200,000
6.501% 2006 - May 15 160,000 -
-------- --------
Total $160,000 $200,000
======== ========
(a) Redemed 9/25/02
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ ------------------
8-3/8 2025 - Sept 30 $ - $ 72,843
7.92 2027 - March 31 - 40,000
Unamortized Discount - (2,870)
-------- --------
Total $ - $109,973
======== ========
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 43,000
2004 52,500
2005 36,000
2006 160,000
2007 -
Later Years 332,245
--------
Total Principal Amount 623,745
Unamortized Discount (2,119)
--------
Total $621,626
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------
The notes to CSPCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to CSPCo. The combined footnotes
begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors
of Columbus Southern Power Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Columbus Southern Power Company and subsidiaries
as of December 31, 2002 and 2001, and the related consolidated statements of
income, comprehensive income, retained earnings, and cash flows for each of the
three years in the period ended December 31, 2002. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Columbus Southern Power Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
Year Ended December 31,
-----------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,526,764 $1,526,997 $1,488,209 $1,351,666 $1,405,794
Operating Expenses 1,375,575 1,367,292 1,522,911 1,243,014 1,239,787
---------- ---------- ---------- ---------- ----------
Operating Income
(Loss) 151,189 159,705 (34,702) 108,652 166,007
Nonoperating Items,
Net 16,726 9,730 9,933 4,530 (839)
Interest Charges 93,923 93,647 107,263 80,406 68,540
---------- ---------- ---------- ---------- ----------
Net Income (Loss) 73,992 75,788 (132,032) 32,776 96,628
Preferred Stock
Dividend
Requirements 4,601 4,621 4,624 4,885 4,824
---------- ---------- --------- ---------- ----------
Earnings (Loss)
Applicable to
Common Stock $ 69,391 $ 71,167 $(136,656) $ 27,891 $ 91,804
========== ========== ========= ========== ==========
December 31,
-----------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,029,958 $4,923,721 $4,871,473 $4,770,027 $4,631,848
Accumulated
Depreciation and
Amortization 2,568,604 2,436,972 2,280,521 2,194,397 2,081,355
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $2,461,354 $2,486,749 $2,590,952 $2,575,630 $2,550,493
========== ========== ========== ========== ==========
Total Assets $4,587,191 $4,394,062 $5,774,108 $4,575,210 $4,148,523
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 915,144 $ 789,800 $ 789,656 $ 789,323 $ 789,189
Accumulated Other
Comprehensive Income
(Loss) (40,487) (3,835) - - -
Retained Earnings 143,996 74,605 3,443 166,389 253,154
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,018,653 $ 860,570 $ 793,099 $ 955,712 $1,042,343
========== ========== ========== ========== ==========
Cumulative Preferred
Stock:
Not Subject to
Mandatory
Redemption $ 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273
Subject to
Mandatory
Redemption (a) 64,945 64,945 64,945 64,945 68,445
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 73,046 $ 73,681 $ 73,681 $ 74,193 $ 77,718
========== ========== ========== ========== ==========
Long-term Debt (a) $1,617,062 $1,652,082 $1,388,939 $1,324,326 $1,175,789
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 50,848 $ 61,933 $ 163,173 $ 187,965 $ 186,427
========== ========== ========== ========== ==========
Total Capitalization
And Liabilities $4,587,191 $4,394,062 $5,774,108 $4,575,210 $4,148,523
========== ========== ========== ========== ==========
(a) Including portion due within one year. (a)
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------
I&M is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 571,000 retail customers in its service
territory in northern and eastern Indiana and a portion of southwestern
Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the
costs of the AEP Power Pool's wholesale sales to neighboring utilities and power
marketers. I&M also sells wholesale power to municipalities and electric
cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing revenues
and costs. The result of this calculation is each company's member load ratio
(MLR) which determines each company's percentage share of revenues and costs.
Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW
Rockport Plant capacity unless it is sold to other utilities. AEGCo is an
affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo
and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to
KPCo through 2004. The KPCo agreement extends until December 31, 2009 for
Rockport Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes operative.
Therefore, I&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.
Results of Operations
- ---------------------
During 2002 Net Income decreased by $2 million due to increased operations and
maintenance costs incurred as part of planned and unplanned outages at Cook
Plant and Rockport Plant.
During 2000 both of the Cook Plant nuclear units were successfully restarted
after being shutdown in September 1997 due to questions regarding the
operability of certain safety systems which arose during a NRC architect
engineer design inspection (see Note 5).
As a result of costs incurred in 2000 to restart the Cook Plant and a
disallowance of interest deductions for a corporate owned life insurance (COLI)
program, Net Income increased in 2001 by $208 million. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including I&M, in a suit over deductibility of interest
claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 I&M
paid the disputed taxes and interest attributable to the COLI interest
deductions for the taxable years 1991-98 and deferred them. The deferrals were
expensed and impacted Net Income in 2000.
Operating Revenues Increase
- ---------------------------
Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase
reflects increased sales to AEP affiliates through the AEP Power Pool. The
following analyzes the changes in Operating Revenues:
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
2002 2001
------------------------------
Amount % Amount %
------ - ------ -
Retail* $ 28.2 4 $ (2.3) N.M
Marketing 2.6 1 (12.0) (4)
Other 2.6 6 5.0 13
------ ------
Total
Wholesale
Electricity 33.4 3 (9.3) (1)
Energy
Delivery* 7.3 2 3.4 1
Sales to AEP
Affiliates (40.9) (16) 44.7 21
------ ------
Total $ (0.2) N.M. $ 38.8 3
====== ======
N.M. = Not Meaningful
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery. The increase in Operating
Revenues in 2001 is primarily due to increased sales to AEP affiliates
reflecting increased availablility of the Cook Plant. The return to service of
the Cook Plant units increased the amount of power I&M could sell to its
affiliates in the AEP Power Pool.
Operating Expenses
- ------------------
Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The
2001 decrease was primarily due to the unfavorable COLI tax ruling and costs
related to the extended Cook Plant outage and restart efforts in 2000. The
changes in the components of Operating Expenses were:
Increase (Decrease)
From Previous Year
-------------------
(dollars in millions)
2002 2001
-----------------------------
Amount % Amount %
------ - ------ -
Fuel $(10.6) (4) $ 39.2 19
Wholesale
Electricity
Purchases 4.7 25 4.9 36
AEP Affiliate
Purchases (4.5) (2) (27.2) (10)
Other Operation 13.6 3 (147.7) (25)
Maintenance 24.3 19 (92.6) (42)
Depreciation and
Amortization 3.8 2 9.3 6
Taxes Other Than
Income Taxes (7.8) (12) 4.9 8
Income Taxes (15.2) (28) 53.6 N.M.
------ -------
Total $ 8.3 1 $(155.6) (10)
====== =======
N.M. = Not Meaningful
Fuel expense decreased in 2002 due to lower average costs of fuel and a decline
in nuclear generation. The increase in Fuel expense in 2001 reflects an increase
in nuclear generation as the Cook Plant units returned to service following the
extended outage.
Wholesale Electricity purchases increased in 2002 and 2001 due to increased
purchases from third parties for sales for resale. AEP Affiliates purchases
declined in 2002 due to lower purchases from AEGCo at lower costs. The decline
in purchased power from AEP affiliates in 2001 reflects generation from the Cook
Plant replacing purchases from the AEP Power Pool which declined 21%.
Other Operation expense increased in 2002 primarily due to higher costs for
pensions, other benefits and insurance. The decrease in Other Operation and
Maintenance expenses in 2001 was primarily due to the cessation of expenditures
to prepare the Cook Plant nuclear units for restart with their return to service
in 2000. Maintenance expense increased for nuclear maintenance costs incurred
during refueling outages in 2002.
The increase in Depreciation and Amortization charges in 2001 reflects increased
generation and distribution plant investments and amortization of I&M's share of
deferred merger costs.
Due to a change in the Indiana property tax law which lowered the floor
percentage for calculating tax liability, Taxes Other Than Income Taxes declined
in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and
personal property tax expense from the effect of a favorable accrual adjustment
of amounts recorded in December 2000 to actual expenses.
Income Taxes attributable to operations decreased in 2002 due to a decrease in
pre-tax operating income. The significant increase in Income Taxes attributable
to operations in 2001 is due to an increase in pre-tax operating income.
Nonoperating Income, Nonoperating Expenses and Income Taxes
- -----------------------------------------------------------
The decrease in Nonoperating Income in 2002 is primarily due to decreased net
gains on forward electricity trading transactions outside AEP's traditional
marketing area. The increase in Nonoperating Income in 2001 is primarily due to
increased net gains on forward electricity trading transactions outside AEP's
traditional marketing area.
Nonoperating Expenses decreased in 2002 due to decreased trading overheads and
traders' incentive compensation. Nonoperating Expenses increased in 2001 due to
increased trading overheads and traders' incentive compensation.
The increase in Nonoperating Income Taxes in 2001 reflects the increase in
nonoperating pre-tax income.
Interest Charges
- ----------------
The decrease in 2001 Interest Charges reflects the recognition in 2000 of
deferred interest payments to the IRS on disputed income taxes from the
disallowance of tax deductions for COLI interest for the years 1991-1998.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $ 990,905 $ 957,548 $ 966,882
Energy Delivery 321,721 314,410 311,019
Sales to AEP Affiliates 214,138 255,039 210,308
---------- ---------- ----------
TOTAL OPERATING REVENUES 1,526,764 1,526,997 1,488,209
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 239,455 250,098 210,870
Purchased Power:
Wholesale Electricity 23,443 18,707 13,785
AEP Affiliates 233,724 238,237 265,475
Other Operation 462,707 449,115 596,861
Maintenance 151,602 127,263 219,854
Depreciation and Amortization 168,070 164,230 154,920
Taxes other Than Income Taxes 57,721 65,518 60,622
Income Taxes 38,853 54,124 524
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,375,575 1,367,292 1,522,911
---------- ---------- ----------
OPERATING INCOME (LOSS) 151,189 159,705 (34,702)
NONOPERATING INCOME 93,739 97,810 76,499
NONOPERATING EXPENSES 71,029 83,037 62,377
NONOPERATING INCOME TAXES 5,984 5,043 4,189
INTEREST CHARGES 93,923 93,647 107,263
---------- ---------- ----------
NET INCOME (LOSS) 73,992 75,788 (132,032)
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,601 4,621 4,624
---------- ---------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 69,391 $ 71,167 $(136,656)
========== ========== =========
Consolidated Statements of Comprehensive Income
- -----------------------------------------------
Year Ended December 31,
--------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME (LOSS) $ 73,992 $75,788 $(132,032)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 3,835 (3,835) -
Cash Flow Power Hedge (286) - -
Minimum Pension Liability (40,201) - -
-------- ------- ---------
COMPREHENSIVE INCOME (LOSS) $ 37,340 $71,953 $(132,032)
======== ======= =========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------
Year Ended December 31,
--------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $ 74,605 $ 3,443 $ 166,389
Net Income (Loss) 73,992 75,788 (132,032)
-------- -------- ---------
148,597 79,231 34,357
-------- -------- ---------
Deductions:
Cash Dividends Declared:
Common Stock - - 26,290
Cumulative Preferred Stock:
4-1/8% Series 229 229 230
4.56% Series 66 66 66
4.12% Series 52 72 74
5.90% Series 897 897 897
6-1/4% Series 1,203 1,203 1,203
6.30% Series 834 834 834
6-7/8% Series 1,186 1,186 1,186
-------- -------- ---------
Total Cash Dividends Declared 4,467 4,487 30,780
Capital Stock Expense 134 139 134
-------- -------- ---------
Total Deductions 4,601 4,626 30,914
-------- -------- ---------
Retained Earnings December 31 $143,996 $ 74,605 $ 3,443
======== ======== =======
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,768,463 $2,758,160
Transmission 971,599 957,336
Distribution 921,835 900,921
General (including nuclear fuel) 220,137 233,005
Construction Work in Progress 147,924 74,299
---------- ----------
Total Electric Utility Plant 5,029,958 4,923,721
Accumulated Depreciation and Amortization 2,568,604 2,436,972
---------- ----------
NET ELECTRIC UTILITY PLANT 2,461,354 2,486,749
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 870,754 834,109
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83,265 82,898
---------- ----------
OTHER PROPERTY AND INVESTMENTS 120,941 127,977
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 3,237 16,804
Advances to Affiliates 191,226 46,309
Accounts Receivable:
Customers 67,333 60,864
Affiliated Companies 122,489 31,908
Miscellaneous 30,468 25,398
Allowance for Uncollectible Accounts (578) (741)
Fuel 32,731 28,989
Materials and Supplies 95,552 91,440
Energy Trading and Derivative Contracts 68,148 108,895
Accrued Utility Revenues 6,511 2,072
Prepayments and Other 11,899 6,497
---------- ----------
TOTAL CURRENT ASSETS 629,016 418,435
---------- ----------
REGULATORY ASSETS 348,212 408,927
---------- ----------
DEFERRED CHARGES 73,649 34,967
---------- ----------
TOTAL ASSETS $4,587,191 $4,394,062
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 858,560 733,216
Accumulated Other Comprehensive Income (Loss) (40,487) (3,835)
Retained Earnings 143,996 74,605
---------- ----------
Total Common Shareholder's Equity 1,018,653 860,570
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,101 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,587,062 1,312,082
---------- ----------
TOTAL CAPITALIZATION 2,678,761 2,246,333
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 620,672 600,244
Other 138,965 87,025
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 759,637 687,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 30,000 340,000
Accounts Payable - General 125,048 86,766
Accounts Payable - Affiliated Companies 93,608 43,956
Taxes Accrued 71,559 69,761
Interest Accrued 21,481 20,691
Obligations Under Capital Leases 8,229 10,840
Energy Trading and Derivative Contracts 48,568 93,413
Other 92,822 76,486
---------- ----------
TOTAL CURRENT LIABILITIES 491,315 741,913
---------- ----------
DEFERRED INCOME TAXES 356,197 400,531
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 97,709 105,449
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 73,885 77,592
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32,261 42,936
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 92,039
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,587,191 $4,394,062
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ 73,992 $ 75,788 $(132,032)
Adjustments for Noncash Items:
Depreciation and Amortization 168,070 166,360 163,391
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) (26,577) 418 5,737
Amortization of Nuclear Outage Costs 40,000 40,000 40,000
Deferred Income Taxes (16,921) (29,205) (125,179)
Deferred Investment Tax Credits (7,740) (8,324) (7,854)
Unrecovered Fuel and Purchased Power Costs 37,501 37,501 37,501
Changes in Certain Current Assets
And Liabilities:
Accounts Receivable (net) (102,283) 64,841 (25,305)
Fuel, Materials and Supplies (7,854) (19,426) 10,743
Accrued Utility Revenues (4,439) (2,072) 44,428
Accounts Payable 87,934 (60,185) 85,056
Taxes Accrued 1,798 1,345 19,446
Mark-to-Market of Energy Trading and Derivatives Contracts (9,517) (62,647) 14,830
Disputed Tax and Interest Related to COLI - - 56,856
Regulatory Asset - Trading Losses (992) 8,493 (17,914)
Regulatory Liability - Trading Gains 2,494 34,293 (7,416)
Change in Other Assets (28,233) (5,871) (68,160)
Change in Other Liabilities 21,001 (5,102) 37,309
--------- --------- ---------
Net Cash Flows From Operating Activities 228,234 236,207 131,437
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (167,484) (91,052) (171,071)
Buyout of Nuclear Fuel Leases - (92,616) -
Other 1,759 1,074 587
--------- --------- ---------
Net Cash Flows Used For Investing Activities (165,725) (182,594) (170,484)
--------- --------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 125,000 - -
Issuance of Long-term Debt 288,732 297,656 199,220
Retirement of Cumulative Preferred Stock (424) - (314)
Retirement of Long-term Debt (340,000) (44,922) (148,000)
Change in Advances from Affiliates (net) (144,917) (299,891) 253,582
Change in Short-term Debt (net) - - (224,262)
Dividends Paid on Common Stock - - (26,290)
Dividends Paid on Cumulative Preferred Stock (4,467) (4,487) (3,368)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (76,076) (51,644) 50,568
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents (13,567) 1,969 11,521
Cash and Cash Equivalents January 1 16,804 14,835 3,314
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 3,237 $16,804 $14,835
======= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000
and $82,511,000 and for income taxes was $60,523,000, $100,470,000 and
$73,254,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under
capital leases were $1,023,000 and $22,218,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,018,653 $ 860,570
---------- ----------
PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 (a) Year Ended December 31, December 31, 2002
- ------ ------------ ------------------------ -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption-$100 Par:
4-1/8% 106.125 20 - 3,750 55,369 5,537 5,539
4.56% 102 - - - 14,412 1,441 1,441
4.12% 102.728 6,326 - 1,375 11,230 1,123 1,756
---------- ----------
8,101 8,736
---------- ----------
Subject to Mandatory Redemption-$100 Par(b):
5.90% (c) - - - 152,000 15,200 15,200
6-1/4% (c) - - - 192,500 19,250 19,250
6.30% (c) - - - 132,450 13,245 13,245
6-7/8% (d) - - - 172,500 17,250 17,250
---------- ----------
64,945 64,945
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 174,245 264,141
Installment Purchase Contracts 310,336 310,239
Senior Unsecured Notes 747,027 696,144
Other Long-term Debt (e) 223,736 219,947
Junior Debentures 161,718 161,611
Less Portion Due Within One Year (30,000) (340,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,587,062 1,312,082
---------- ----------
TOTAL CAPITALIZATION $2,678,761 $2,246,333
========== ==========
(a) The cumulative preferred stock is callable at the price indicated plus
accrued dividends
(b) Sinking fund provisions require the redemption of 15,000 shares in 2003 and
67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
provisions of each series subject to mandatory redemption have been met by
purchase of shares in advance of these due dates. Shares previously
purchased may be applied to meet the sinking fund requirement.
(c) Commencing in 2004 and continuing through 2008 I&M may redeem, at $100 per
share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4%
series and 17,500 shares of the 6.30% series outstanding under sinking fund
provisions at its option and all remaining outstanding shares must be
redeemed not later than 2009. The series are callable beginning November 1,
2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March
1, 2004 for the 6.30% series at $100 plus accrued dividends.
(d) Commencing in 2003 and continuing through the year 2007, a sinking fund
will require the redemption of 15,000 shares each year and the redemption
of the remaining shares outstanding on April 1, 2008, in each case at $100
per share. Callable at $100 per share plus accrued dividends beginning
February 1, 2003.
(e) Represents a liability for SNF disposal including interest payable to the
DOE. See Note 9.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
7.60 2002 - November 1 $ - $ 50,000
7.70 2002 - December 15 - 40,000
6.10 2003 - November 1 30,000 30,000
8.50 2022 - December 15 75,000 75,000
7.35 2023 - October 1 15,000 15,000
7.20 2024 - February 1 30,000 30,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (755) (859)
-------- --------
$174,245 $264,141
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered in connection with the issuance
of pollution control revenue bonds by governmental authorities as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7.00 2015 - April 1 $ 25,000 $ 25,000
5.90 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 - 50,000
7.60 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
4.90(c) 2025 - June 1 50,000 -
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (1,664) (1,761)
-------- --------
$310,336 $310,239
======== ========
(a) A variable interest rate was determined weekly. The average weighted
interest rates were 1.5% in 2002 and 2.4% for 2001.
(b) In June 2001 an auction rate was established. Auction rates are determined
by standard procedures every 35 days. The auction rate for 2002 ranged from
1.3% to 1.7% and averaged 1.5%. The auction rate for June through December
2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001,
an adjustable interest rate was a daily, weekly, commercial paper or term
rate as designated by I&M. A weekly rate was selected which ranged from
1.9% to 4.9% in 2001 and averaged 3.3% during 2001.
(c) Rate is fixed until June 1, 2007 (term rate bonds).
The terms of the installment purchase contracts require I&M to pay amounts
sufficient for the cities to pay interest on and the principal of (at stated
maturities and upon mandatory redemptions) related pollution control revenue
bonds issued to finance the construction of pollution control facilities at
certain generating plants. The term rate bonds due 2025 are subject to mandatory
tender for purchase on the term maturity date (June 1, 2007). Accordingly, the
term rate bonds have been classified for repayment purposes in 2007 (the term
end date).
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2002 - September 3 $ - $200,000
6-7/8 2004 - July 1 150,000 150,000
6.125 2006 - December 15 300,000 300,000
6.45 2008 - November 10 50,000 50,000
6.375 2012 - November 1 100,000 -
6 2032 - December 31 150,000 -
Unamortized Discount (2,973) (3,856)
-------- --------
$747,027 $696,144
======== ========
(a) A floating interest rate was determined quarterly. The rate on December 31,
2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ -----------------
8.00 2026 - March 31 $ 40,000 $ 40,000
7.60 2038 - June 30 125,000 125,000
Unamortized Discount (3,282) (3,389)
-------- --------
Total $161,718 $161,611
======== ========
Interest may be deferred and payment of principal and interest on the junior
debentures is subordinated and subject in right to the prior payment in full of
all senior indebtedness of I&M.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 30,000
2004 150,000
2005 -
2006 300,000
2007 50,000
Later Years 1,095,736
----------
Total Principal Amount 1,625,736
Unamortized Discount (8,674)
----------
Total $1,617,062
==========
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
The notes to I&M's consolidated financial statements are combined with the notes
to financial statements for AEP and its other subsidiary registrants. Listed
below are the combined notes that apply to I&M. The combined footnotes begin on
page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Merger Note 4
Nuclear Plant Restart Note 5
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Indiana Michigan Power Company and subsidiaries
as of December 31, 2002 and 2001, and the related consolidated statements of
income, comprehensive income, retained earnings and cash flows for each of the
three years in the period ended December 31, 2002. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Indiana Michigan Power Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY
Selected Financial Data
- -----------------------
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 378,683 $ 379,025 $ 389,875 $ 358,757 $ 362,999
Operating Expenses 336,486 331,347 340,137 304,082 311,106
---------- ----------- ---------- ---------- ----------
Operating Income 42,197 47,678 49,738 54,675 51,893
Nonoperating
Items, Net 5,206 1,248 2,070 (327) (1,726)
Interest Charges 26,836 27,361 31,045 28,918 28,491
---------- ----------- ---------- ---------- ----------
Net Income $ 20,567 $ 21,565 $ 20,763 $ 25,430 $ 21,676
========== =========== ========== ========== ==========
Year Ended December 31,
--------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $1,295,619 $1,128,415 $1,103,064 $1,079,048 $1,043,711
Accumulated
Depreciation and
Amortization 397,304 384,104 360,648 340,008 315,546
---------- ---------- ---------- ---------- ----------
Net Electric
Utility Plant $ 898,315 $744,311 $742,416 $739,040 $728,165
========== ======== ======== ======== ========
Total Assets $1,164,676 $ 999,048 $1,494,543 $ 986,123 $ 921,847
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 259,200 $ 209,200 $209,200 $209,200 $199,200
Accumulated Other
Comprehensive
Income (Loss) (9,451) (1,903) - - -
Retained Earnings 48,269 48,833 57,513 67,110 71,452
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's
Equity $ 298,018 $ 256,130 $266,713 $276,310 $270,652
========== ========== ======== ======== ========
Long-term
Debt (a) $ 466,632 $ 346,093 $330,880 $365,782 $368,838
========== ========== ======== ======== ========
Obligations Under
Capital Leases(a)
$ 7,248 $ 9,583 $ 14,184 $ 15,141 $ 18,977
========== ========== ======== ======== ========
Total
Capitalization
and Liabilities $1,164,676 $ 999,048 $1,494,543 $ 986,123 $ 921,847
========== ========== ========== ========== ==========
(a) Including portion due within one year.
KENTUCKY POWER COMPANY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------
KPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power serving 174,000 retail customers in eastern
Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and
costs of the AEP Power Pool's wholesale sales to neighboring utility systems and
power marketers including power trading transactions. KPCo also sells wholesale
power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
KPCo has a unit power agreement with AEGCo, an affiliated company, which expires
in 2004. The unit power agreement extends until December 31, 2009 for Rockport
Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP's
settlement restructuring agreement filed with the FERC becomes operative. The
agreement provides for KPCo to purchase 15% of the total output of the two unit
2,600-mw capacity Rockport Plant. Under the unit power agreement, there is a
demand charge for the right to receive the power, which is payable even it the
power is not taken. The amount of the demand charge is such that when added to
other amounts received by AEGCo, it will enable AEGCo to recover all its fixed
expenses including a FERC-approved rate of return on common equity.
Results of Operations
- ---------------------
Net Income for 2002 decreased $1 million or 5%. Total Revenues were flat while
increases in Operating Expenses, driven by expenses related to planned outages
at the Big Sandy plant, were offset by comparable gains in net nonoperating
income which benefited from decreases in trading incentive compensation.
Changes in Revenues
- -------------------
Increase (Decrease)
Year-to-Date
-------------------
(dollars in millions)
Amount %
------ -
Wholesale Electricity* $13 6
Energy Delivery* 1 1
Sales to AEP Affiliates (14) (34)
---
Total $ - -
===
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Revenues in 2002 were comparable to those of last year. Increased sales to
retail electricity customers reflecting warmer summer weather, colder days in
late 2002, and increased fuel recovery revenues were offset by lower Sales to
AEP Affiliates resulting from planned outages in 2002. KPCo's decreased
generation was due to scheduled maintenance resulting in lower availability in
the fourth quarter.
Changes in Operating Expenses
- -----------------------------
Increase (Decrease)
Year-to-Date
-------------------
(dollars in millions)
Amount %
------ -
Fuel $(5.6) (8)
Wholesale Electricity - N.M.
Purchases from AEP Affiliates
2.8 2
Other Operation (5.4) (9)
Maintenance 12.6 56
Depreciation .7 2
Taxes Other Than
Income Taxes .4 5
Income Taxes (.4) (4)
-----
Total Operating Expenses $ 5.1 2
=====
N.M. = Not Meaningful
Fuel expense decreased in 2002 as a result of planned fourth quarter outages at
the Big Sandy plant for scheduled boiler maintenance. The 800 megawatt Unit 2,
representing approximately 75% of the plant's generation capacity, was off-line
from mid-September through the end of the year, thereby reducing the demand for
fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to
meet demand during the planned outages at the Big Sandy plant.
Other Operation expense decreased in 2002 due to reduced consumption of emission
allowances due to the planned outage; reduced accruals for trading incentive
compensation due to reduced trading activity; and improvements in transmission
expense resulting from less wholesale activity and related transmission, and an
increase in AEP transmission equalization credits. Under the AEP Transmission
Equalization Agreement, KPCo and certain eastern region affiliates share the
costs associated with the ownership of their transmission system based upon each
company's peak demand and investment. A decrease in KPCo's peak demand relative
to its affiliates' peak demand was the main reason for the increase in
transmission equalization credits. These developments were offset in part by
severance expenses related to a sustained earnings initiative (see Note 11).
Maintenance expense increased in 2002 primarily as a result of planned power
plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for
planned boiler overhaul and electric plant maintenance. The Company experienced
marginal increases in overhead line maintenance expense.
Nonoperating Income Taxes for 2002 have increased as a result of increases in
pre-tax income for the year offset in part by prior-year tax return adjustments.
Other Changes
- -------------
Nonoperating Income for 2002 decreased as a result of AEP's previously announced
plan to reduce trading activity, and decreased margins on power trading activity
outside of the AEP System's traditional marketing area resulting from soft
market demand. Nonoperating Expenses decreased in 2002 as a result of decreases
in trading incentive compensation.
KENTUCKY POWER COMPANY
Statements of Income
- --------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $218,665 $205,476 $226,708
Energy Delivery 132,054 131,183 121,346
Sales to AEP Affiliates 27,964 42,366 41,821
-------- -------- --------
TOTAL OPERATING REVENUES 378,683 379,025 389,875
-------- -------- --------
OPERATING EXPENSES:
Fuel 65,043 70,635 74,638
Purchased Power:
Wholesale Electricity 29 86 1,940
AEP Affiliates 133,002 130,204 127,707
Other Operation 52,892 58,275 52,495
Maintenance 35,089 22,444 25,866
Depreciation and Amortization 33,233 32,491 31,028
Taxes Other Than Income Taxes 8,240 7,854 7,251
Income Taxes 8,958 9,358 19,212
-------- -------- --------
TOTAL OPERATING EXPENSES 336,486 331,347 340,137
-------- -------- --------
OPERATING INCOME 42,197 47,678 49,738
NONOPERATING INCOME 7,863 10,881 6,139
NONOPERATING EXPENSES 753 8,949 2,940
NONOPERATING INCOME TAXES 1,904 684 1,129
INTEREST CHARGES 26,836 27,361 31,045
-------- -------- --------
NET INCOME $ 20,567 $ 21,565 $ 20,763
======== ======== ========
Statements of Comprehensive Income
- ----------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $ 20,567 $21,565 $20,763
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge 2,225 (1,903) -
Minimum Pension Liability (9,773) - -
-------- ------- -------
COMPREHENSIVE INCOME $ 13,019 $19,662 $20,763
======== ======= =======
Statements of Retained Earnings
- -------------------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $48,833 $57,513 $67,110
NET INCOME 20,567 21,565 20,763
CASH DIVIDENDS DECLARED 21,131 30,245 30,360
------- ------- -------
RETAINED EARNINGS DECEMBER 31 $48,269 $48,833 $57,513
======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Balance Sheets
- --------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 275,121 $ 271,070
Transmission 373,639 374,116
Distribution 425,817 402,537
General 55,913 65,059
Construction Work in Progress 165,129 15,633
---------- ----------
Total Electric Utility Plant 1,295,619 1,128,415
Accumulated Depreciation and Amortization 397,304 384,104
---------- ----------
NET ELECTRIC UTILITY PLANT 898,315 744,311
---------- ----------
OTHER PROPERTY AND INVESTMENTS 6,904 6,492
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 29,871 29,477
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 2,304 1,947
Accounts Receivable:
Customers 22,044 20,036
Affiliated Companies 23,802 16,012
Miscellaneous 2,889 3,333
Allowance for Uncollectible Accounts (192) (264)
Fuel 10,817 12,060
Materials and Supplies 16,127 15,766
Accrued Utility Revenues 5,301 5,395
Accrued Tax Benefit 1,253 -
Energy Trading Contracts 24,320 33,905
Prepayments and other 2,127 1,314
---------- ----------
TOTAL CURRENT ASSETS 110,792 109,504
---------- ----------
REGULATORY ASSETS 101,976 97,692
---------- ----------
DEFERRED CHARGES 16,818 11,572
---------- ----------
TOTAL ASSETS $1,164,676 $ 999,048
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 208,750 158,750
Accumulated Other Comprehensive Income (Loss) (9,451) (1,903)
Retained Earnings 48,269 48,833
---------- --------
Total Common Shareowner's Equity 298,018 256,130
Long-term Debt 391,632 176,093
Long-term Debt - Affiliated Companies 60,000 75,000
---------- --------
TOTAL CAPITALIZATION 749,650 507,223
---------- --------
OTHER NONCURRENT LIABILITIES 27,319 11,929
---------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General - 95,000
Long-term Debt Due within One Year -
Affiliated Companies 15,000 -
Advances from Affiliates 23,386 66,200
Accounts Payable:
General 46,515 23,464
Affiliated Companies 44,035 22,557
Customer Deposits 8,048 4,461
Taxes Accrued - 10,305
Interest Accrued 6,471 5,269
Energy Trading and Derivative Contracts 17,803 38,664
Other 14,322 12,882
---------- --------
TOTAL CURRENT LIABILITIES 175,580 278,802
---------- --------
DEFERRED INCOME TAXES 178,313 168,304
---------- --------
DEFERRED INVESTMENT TAX CREDITS 9,165 10,405
---------- --------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 11,488 14,917
---------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 13,161 7,468
---------- --------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $1,164,676 $999,048
========== ========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Statements of Cash Flows
- ------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 20,567 $ 21,565 $ 20,763
Adjustments for Noncash Items:
Depreciation and Amortization 33,233 32,491 31,034
Deferred Income Taxes 9,839 6,293 3,765
Deferred Investment Tax Credits (1,240) (1,251) (1,252)
Deferred Fuel Costs (net) 2,998 (4,707) 2,948
Mark-to-Market of Energy Trading Contracts (12,267) (1,454) (4,376)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) (9,426) 23,694 (20,930)
Fuel, Materials and Supplies 882 (7,658) 8,386
Accrued Utility Revenues 94 1,105 7,237
Accounts Payable 44,529 (22,942) 39,883
Taxes Accrued (11,558) (1,580) 2,025
Disputed Tax and Interest Related to COLI - - 5,943
Change in Other Assets (21,491) (2,762) 62,653
Change in Other Liabilities 16,161 (9,446) (62,702)
--------- -------- ---------
Net Cash Flows From Operating Activities 72,321 33,348 95,377
--------- -------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (178,700) (37,206) (36,209)
Proceeds From Sales of Property 217 216 266
--------- -------- ---------
Net Cash Flows Used For Investing
Activities (178,483) (36,990) (35,943)
--------- -------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 50,000 - -
Issuance of Long-term Debt 274,964 75,000 69,685
Retirement of Long-term Debt (154,500) (60,000) (105,000)
Change in Short-term Debt (net) - - (39,665)
Change in Advances From Affiliates (net) (42,814) 18,564 47,636
Dividends Paid (21,131) (30,245) (30,360)
--------- -------- ---------
Net Cash Flows From (Used For)
Financing Activities 106,519 3,319 (57,704)
--------- -------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 357 (323) 1,730
Cash and Cash Equivalents January 1 1,947 2,270 540
--------- -------- ---------
Cash and Cash Equivalents December 31 $ 2,304 $ 1,947 $ 2,270
========= ======== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000
and $28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000
in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases
were $22,021, $817,000 and $2,817,000 and in 2002, 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Statements of Capitalization
- ----------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $298,018 $256,130
-------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds - 59,383
Senior Unsecured Notes 352,508 147,625
Notes Payable 75,000 100,000
Junior Debentures 39,124 39,085
Less Portion Due Within One Year (15,000) (95,000)
-------- - -------
Long-term Debt Excluding Portion Due Within One Year 451,632 251,093
-------- - -------
TOTAL CAPITALIZATION $749,650 $507,223
======== ========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6.65 2003 - May 1 $ - $ 15,000
6.70 2003 - June 1 - 15,000
6.70 2003 - July 1 - 15,000
7.90 2023 - June 1 - 14,500
Unamortized Discount - (117)
-------- --------
$ - $ 59,383
======== ========
First mortgage bonds were secured by a first mortgage lien on electric utility
plant.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2002 - November 19 $ - $ 70,000
6.91 2007 - October 1 48,000 48,000
6.45 2008 - November 10 30,000 30,000
5.50 2007 - July 125,000 -
4.31 2007 - November 12 80,400 -
4.37 2007 - December 12 69,564 -
Unamortized Discount (456) (375)
-------- --------
$352,508 $147,625
(a) A floating interest rate is determined monthly. The rate December 31, 2001
was 4.3%.
Notes payable to parent company were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
4.336 2003 - May 15 $15,000 $15,000
6.501 2006 - May 15 60,000 60,000
------- -------
$75,000 $75,000
Notes payable to banks outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
7.45 2002 - September 20 $ - $25,000
======= =======
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (876) (915)
------- -------
Total $39,124 $39,085
======= =======
Interest may be deferred and payment of principal and interest on the junior
debentures is subordinated and subject in right to the prior payment in full of
all senior indebtedness of the Company.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 15,000
2004 -
2005 -
2006 60,000
2007 322,964
Later Years 70,000
--------
Total Principal Amount 467,964
Unamortized Discount (1,332)
--------
Total $466,632
========
KENTUCKY POWER COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------
The notes to KPCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to KPCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of
Directors of Kentucky Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Kentucky Power Company as of December 31, 2002 and 2001, and the related
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kentucky Power Company as of December 31,
2002 and 2001, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
OHIO POWER COMPANY
OHIO POWER COMPANY
Selected Financial Data
- -----------------------
Year Ended December 31,
---------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $2,113,125 $2,098,105 $2,140,331 $1,978,826 $2,105,547
Operating Expenses 1,814,796 1,857,395 1,913,504 1,689,997 1,816,175
---------- ---------- ---------- ---------- ----------
Operating Income 298,329 240,710 226,827 288,829 289,372
Nonoperating Items,
Net 5,376 18,686 (5,004) 7,000 588
Interest Charges 83,682 93,603 119,210 83,672 80,035
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 220,023 165,793 102,613 212,157 209,925
Extraordinary Loss - (18,348) (18,876) - -
---------- ---------- --------- ---------- ----------
Net Income 220,023 147,445 83,737 212,157 209,925
Preferred Stock
Dividend
Requirements 1,258 1,258 1,266 1,417 1,474
---------- ---------- ---------- ---------- ----------
Earnings Applicable
To Common Stock $ 218,765 $ 146,187 $ 82,471 $ 210,740 $ 208,451
========== ========== ========== ========== ==========
Year Ended December 31,
---------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,685,826 $5,390,576 $5,577,631 $5,400,917 $5,257,841
Accumulated
Depreciation 2,566,828 2,452,571 2,764,130 2,621,711 2,461,376
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $3,118,998 $2,938,005 $2,813,501 $2,779,206 $2,796,465
========== ========== ========== ========== ==========
Total Assets $4,457,032 $4,394,073 $6,193,975 $4,675,159 $4,344,680
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $783,684 $783,684 $783,684 $783,577 $783,536
Accumulated Other
Comprehensive Income
(Loss) (72,886) (196) - - -
Retained Earnings 522,316 401,297 398,086 587,424 587,500
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,233,114 $1,184,785 $1,181,770 $1,371,001 $1,371,036
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 16,648 $ 16,648 $ 16,648 $ 16,937 $ 17,370
Subject to Mandatory
Redemption (a) 8,850 8,850 8,850 8,850 11,850
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 25,498 $ 25,498 $ 25,498 $ 25,787 $ 29,220
========== ========== ========== ========== ==========
Long-term Debt (a) $1,067,314 $1,203,841 $1,195,493 $1,151,511 $1,084,928
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 65,626 $ 80,666 $ 116,581 $ 136,543 $ 142,635
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $4,457,032 $4,394,073 $6,193,975 $4,675,159 $4,344,680
========== ========== ========== ========== ==========
(a) Including portion due within one year.
OHIO POWER COMPANY
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------
Ohio Power Company (OPCo) is a public utility engaged in the generation,
purchase, sale, transmission and distribution of electric power to 702,000
retail customers in northwestern, east central, eastern and southern sections of
Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues
and costs of the AEP Power Pool's wholesale sales to neighboring utility systems
and power marketers including power trading transactions. OPCo also sells
wholesale power to municipalities and cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges or the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
Results of Operations
- ---------------------
Income Before Extraordinary Item increased $54 million or 33% in 2002 mainly due
to reductions in operating expenses, predominantly fuel, and interest charges.
Income Before Extraordinary Item increased $63 million or 62% in 2001 primarily
due to the effect of a court decision related to a corporate owned life
insurance (COLI) program recorded in 2000. In February 2001 the U.S. District
Court for the Southern District of Ohio ruled against AEP and certain of its
subsidiaries, including OPCo, in a suit over deductibility of interest claimed
in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid
the disputed taxes and interest attributable to the COLI interest deductions for
taxable years 1991-98. The payments were included in Other Property and
Investments pending the resolution of this matter. Net Income was also favorably
impacted by the growth in and strong performance by the wholesale business. The
effects of the COLI decision in 2000 and favorable wholesale business in 2001
were offset in part by the commencement of the amortization of transition
regulatory assets in 2001, the effect of mild winter weather and the economic
downturn.
Operating Revenues
- ------------------
Operating Revenues increased 1% in 2002 mainly as a result of increased
residential and commercial sales due to demand caused by weather conditions.
Changes in the components of Operating Revenues were:
Increase (Decrease)
From Previous Year
------------------
(Dollars in Millions)
2002 2001
-----------------------------
Amount % Amount %
------ - ------ -
Retail* $ 11 2 $(66) (8)
Wholesale
Marketing 10 5 (19) (8)
Unrealized MTM 2 8 33 N.M.
Other 1 1 (4) (5)
---- ----
Total
Wholesale
Electricity* 24 2 (56) (5)
Energy
Delivery* 37 7 85 18
Sales to AEP
Affiliates (46) (9) (71)(12)
---- ----
Total $ 15 1 $(42) (2)
==== ====
* Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
During the summer months, cooling degree days increased 39%. For the fall
season, heating degree days increased 32%. This reflects a return to more normal
weather conditions since 2001 weather was abnormally mild. Sales to AEP
Affiliates decreased due to a 15% decrease in price, reflective of lower average
fuel cost, while MWH sales rose slightly.
Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power
Pool. This was the result of an affiliate being able to supply more power to the
Power Pool from two nuclear units that returned to service in June and December
2000.
Operating Expenses
- ------------------
Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel.
Operating Expenses in 2001 also decreased 3%. This reduction was the result of
lower Fuel and Income Taxes partially offset by amortization of transition
regulatory assets.
Changes in the components of Operating Expenses were:
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
2002 2001
---- ----
Amount % Amount %
------ - ------ -
Fuel $(102) (15) $(85) (11)
Wholesale
Electricity
Purchased Power 4 6 15 30
AEP Affiliates
Purchased Power 8 14 12 23
Other Operation 16 4 (4) (1)
Maintenance (6) (4) 18 15
Depreciation
and Amortization 9 4 84 54
Taxes Other Than
Income Taxes 16 10 (10) (6)
Income Taxes 12 12 (86) (46)
----- ----
Total Operating
Expenses $ (43) (2) $(56) (3)
===== ====
The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost
of fuel for generation, offset in part by a slight increase in MWH generated.
The decrease in fuel costs are the result of purchasing coal at lower prices on
the open market in 2002 instead of affiliated company coal.
Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net generation
because of decreased sales to the AEP Power Pool caused by an affiliate's two
nuclear units returning to service.
Wholesale Electricity Purchased Power expense increased in 2002. This was the
result of a 11% increase of MWH sales, partially offset by a decrease in price.
In 2001 the increase was due to increases in MWH purchases from third parties
because of the non-availability of associated nuclear power for resale to
wholesale customers and to meet internal demand.
AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18%
increase of MWH purchased from affiliates with a slight decrease in the average
price. The increase for 2001 was also a result of increased purchases through
the AEP Power Pool.
Maintenance expense increased in 2001 mainly due to boiler repairs at Amos,
Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler inspections
at the Amos and Cardinal Plants.
In 2001, the commencement of amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
retail electricity supply under Ohio deregulation accounted for the significant
increase in Depreciation and Amortization expense.
The 2002 increase in Taxes Other Than Income Taxes is the result of increases in
state excise tax created from a change in the base tax calculation. The decrease
in 2001 was due to a decrease in property tax expense reflecting a reduction in
rates on generation property under the Ohio Restructuring law partially offset
by a new state excise tax.
Income Taxes increased in 2002 due to an increase in both federal and state tax
expenses. Federal taxes increased due to higher pre-tax operating income offset
in part by changes in certain book/tax timing differences accounted for on a
flow-thru basis. State taxes increased predominately as a result of the State of
Ohio's tax legislation revision involving utility deregulation.
Income Taxes decreased in 2001 due to an unfavorable ruling in AEP's suit
against the government over interest deductions claimed relating to AEP's COLI
program which was recorded in 2000 and a decrease in pre-tax book income.
Nonoperating Income and Nonoperating Expense
- --------------------------------------------
Nonoperating Expenses decreased during 2002 due to reductions in variable
incentive compensation expenses associated with wholesale trading.
Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of
an increase in the level of trading activity outside of the AEP System's
traditional marketing area.
The 2002 increase in Nonoperating Income Tax Expense is a result of the
favorable tax benefit from the sale of the Ohio Coal companies in 2001. This
event also caused the decrease for 2001.
Interest Charges
- ----------------
The 2002 decrease in Interest Charges was primarily due to a decrease in the
outstanding balances of long-term debt, the refinancing of debt at favorable
interest rates and a reduction in short-term interest rates.
The major reason for the decrease in Interest Charges in 2001 was the
recognition in 2000 of deferred interest payments to the IRS related to COLI
disallowances.
Extraordinary Loss
- ------------------
In the second quarter of 2001 an extraordinary loss of $18 million net of tax
was recorded to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation. In 2000 the application of regulatory accounting for generation
under SFAS 71 was discontinued which resulted in an after tax extraordinary loss
of $19 million.
OHIO POWER COMPANY
Statements of Income
- --------------------
Year Ended December 31,
-------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $1,058,250 $1,034,026 $1,090,297
Energy Delivery 589,673 552,713 467,587
Sales to AEP Affiliates 465,202 511,366 582,447
---------- ---------- ----------
TOTAL OPERATING REVENUES 2,113,125 2,098,105 2,140,331
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 584,730 686,568 771,969
Purchased Power:
Wholesale Electricity 67,385 63,441 48,657
AEP Affiliates 71,154 62,585 50,741
Other Operation 416,533 400,790 404,410
Maintenance 136,609 142,878 124,735
Depreciation and Amortization 248,557 239,982 155,944
Taxes Other Than Income Taxes 176,247 159,778 169,527
Income Taxes 113,581 101,373 187,521
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,814,796 1,857,395 1,913,504
---------- ---------- ----------
OPERATING INCOME 298,329 240,710 226,827
NONOPERATING INCOME 51,953 70,108 57,163
NONOPERATING EXPENSES 28,567 53,802 44,009
NONOPERATING INCOME TAX EXPENSE (CREDIT) 18,010 (2,380) 18,158
INTEREST CHARGES 83,682 93,603 119,210
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 220,023 165,793 102,613
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION -
Net of tax (See Note 2) - (18,348) (18,876)
---------- ---------- ----------
NET INCOME 220,023 147,445 83,737
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,258 1,258 1,266
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 218,765 $ 146,187 $ 82,471
========== ========== ==========
Statements of Comprehensive Income
- ----------------------------------
Year Ended December 31,
-----------------------------------------------
(in thousands)
2002 2001 2000
---- ---- ----
NET INCOME $220,023 $147,445 $83,737
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (542) (196) -
Minimum Pension Liability (72,148) - -
-------- -------- -------
COMPREHENSIVE INCOME $147,333 $147,249 $83,737
======== ======== =======
The common stock of OPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
Statement of Retained Earnings
- ------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Retained Earnings January 1 $401,297 $398,086 $587,424
Net Income 220,023 147,445 83,737
-------- -------- --------
621,320 545,531 671,161
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 97,746 142,976 271,813
Cumulative Preferred Stock:
4.08% Series 58 58 59
4.20% Series 96 96 96
4.40% Series 139 139 139
4-1/2% Series 439 439 442
5.90% Series 428 428 428
6.02% Series 66 66 66
6.35% Series 32 32 32
-------- -------- --------
Total Dividends 99,004 144,234 273,075
-------- -------- --------
Retained Earnings December 31 $522,316 $401,297 $398,086
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
Balance Sheets
- --------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,116,825 $3,007,866
Transmission 905,829 891,283
Distribution 1,114,600 1,081,122
General 260,153 245,232
Construction Work in Progress 288,419 165,073
---------- ----------
Total Electric Utility Plant 5,685,826 5,390,576
Accumulated Depreciation and Amortization 2,566,828 2,452,571
---------- ----------
NET ELECTRIC UTILITY PLANT 3,118,998 2,938,005
---------- ----------
OTHER PROPERTY AND INVESTMENTS 61,686 62,303
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 103,230 99,706
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 5,285 8,848
Accounts Receivable:
Customers 95,100 84,694
Affiliated Companies 124,244 148,563
Miscellaneous 19,281 20,409
Allowance for Uncollectible Accounts (909) (1,379)
Fuel 87,409 84,724
Materials and Supplies 85,379 88,768
Energy Trading Contracts 92,108 114,280
Prepayments and Other 12,083 20,865
---------- ----------
TOTAL CURRENT ASSETS 519,980 569,772
---------- ----------
REGULATORY ASSETS 568,641 644,625
---------- ----------
DEFERRED CHARGES 84,497 79,662
---------- ----------
TOTAL ASSETS $4,457,032 $4,394,073
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (72,886) (196)
Retained Earnings 522,316 401,297
---------- ----------
Total Common Shareholder's Equity 1,233,114 1,184,785
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 917,649 1,203,841
---------- ----------
TOTAL CAPITALIZATION 2,176,261 2,414,124
---------- ----------
OTHER NONCURRENT LIABILITIES 227,689 130,386
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 89,665 -
Long-term Debt Due Within One Year - Affiliated Companies 60,000 -
Short-term Debt - Affiliated Companies 275,000 -
Advances From Affiliates 129,979 300,213
Accounts Payable - General 170,563 131,057
Accounts Payable - Affiliated Companies 145,718 176,520
Customer Deposits 12,969 5,452
Taxes Accrued 111,778 126,770
Interest Accrued 18,809 17,679
Obligations Under Capital Leases 14,360 16,405
Energy Trading Contracts 61,839 98,081
Other 80,608 90,431
---------- ----------
Total CURRENT LIABILITIES 1,171,288 962,608
---------- ----------
DEFERRED INCOME TAXES 794,387 797,889
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 18,748 21,925
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 39,702 50,459
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 28,957 16,682
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $4,457,032 $4,394,073
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
Statements of Cash Flows
- ------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 220,023 $ 147,445 $ 83,737
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 248,557 252,123 200,350
Deferred Income Taxes 46,010 215,833 (65,956)
Deferred Investment Tax Credits (3,177) (3,289) (3,399)
Deferred Fuel Costs (net) - - (56,869)
Extraordinary Loss 18,348 18,876
Mark to Market of Energy Trading Contracts (28,693) (59,833) (5,614)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 14,571 51,640 51,430
Fuel, Materials and Supplies 704 4,852 46,645
Accrued Utility Revenues 3,081 264 45,311
Accounts Payable 8,704 9,887 56,069
Customer Deposits 7,517 (34,284) 31,540
Taxes Accrued (14,992) (96,331) 60,919
Disputed Tax and Interest Related to COLI - - 110,494
Employee Benefit and Other Noncurrent Liabilities 110,298 (392,026) 145,573
Impairment Loss 1,757 - -
Change in Other Assets (2,233) 79,831 (439,448)
Change in Other Liabilities (133,154) (107,704) 359,640
--------- --------- ---------
Net Cash Flows From Operating Activities 478,973 86,756 639,298
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (354,797) (344,571) (254,016)
Proceeds From Sales of Property and Other 6,499 16,778 6,354
Investment in Coal Companies - (32,115) -
--------- --------- ---------
Net Cash Flows Used For
Investing Activities (348,298) (359,908) (247,662)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 300,000 74,748
Change in Advances From Affiliates (net) (170,234) 392,699 (92,486)
Retirement of Cumulative Preferred Stock - - (182)
Retirement of Long-term Debt (140,000) (297,858) (30,663)
Change in Short-term Debt (net) 275,000 - (194,918)
Dividends Paid on Common Stock (97,746) (142,976) (271,813)
Dividends Paid on Cumulative Preferred Stock (1,258) (1,258) (1,262)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (134,238) 250,607 (516,576)
--------- --------- ---------
Net Decrease in Cash and Cash Equivalents (3,563) (22,545) (124,940)
Cash and Cash Equivalents January 1 8,848 31,393 156,333
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 5,285 $ 8,848 $31,393
======= ======= =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $81,041,000,
$94,747,000 and $87,120,000 and for income taxes was $105,058,000, $(22,417,000)
and $142,710,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions
under capital leases were $106,000, $2,380,000 and $17,005,000 in 2002, 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
Statements of Capitalization
- ----------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,233,114 $1,184,785
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 3,762,403
$25 par value - authorized shares 4,000,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 (a) Year Ended December 31, December 31, 2002
- ------ ------------- --------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption-$100 Par:
4.08% $103 - - - 14,595 1,460 1,460
4.20% 103.20 - - 276 22,824 2,282 2,282
4.40% 104 - - 432 31,512 3,151 3,151
4-1/2% 110 - - 2,181 97,546 9,755 9,755
---------- ----------
16,648 16,648
---------- ----------
Subject to Mandatory Redemption-$100 Par (b):
5.90% (c) $ - - - - 72,500 7,250 7,250
6.02% (d) - - - - 11,000 1,100 1,100
6.35% (d) - - - - 5,000 500 500
---------- ----------
8,850 8,850
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 136,633 141,544
Installment Purchase Contracts 233,340 233,235
Senior Unsecured Notes 397,341 396,962
Notes Payable to Affiliated Company 300,000 300,000
Junior Debentures - 132,100
Less Portion Due Within One Year (149,665) -
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 917,649 1,203,841
---------- ----------
TOTAL CAPITALIZATION $2,176,261 $2,414,124
========== ==========
(a) The cumulative preferred stock is callable at the price indicated plus
accrued dividends.
(b) Sinking fund provisions require the redemption of 35,000 shares in 2003 and
57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
provisions of each series subject to mandatory redemption have been met by
purchase of shares in advance of the due dates. Shares previously purchased
may be applied to the sinking fund requirement. At the company's option,
all shares are redeemable at $100 per share plus accrued and unpaid
dividends with at least 30 days notice beginning on or after November 1,
2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April
1, 2003 for the 6.35% series.
(c) Commencing in 2004 and continuing through the year 2008, a sinking fund for
the 5.90% cumulative preferred stock will require the redemption of 22,500
shares each year and the redemption of the remaining shares outstanding on
January 1, 2009, in each case at $100 per share. Shares previously redeemed
may be applied to meet sinking fund requirements.
(d) Commencing in 2003 and continuing through 2007 sinking fund provisions will
require the redemption of 20,000 shares each year of the 6.02% series and
15,000 shares each year of the 6.35% series, in each case at $100 per
share. All remaining outstanding shares must be redeemed in 2008. Shares
previously redeemed may be applied to meet the sinking fund requirements.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6.75 2003 - April 1 $ 29,850 $ 29,850
6.55 2003 - October 1 27,315 27,315
6.00 2003 - November 1 12,500 12,500
6.15 2003 - December 1 20,000 20,000
(a) 2022 - February 10 - 5,000
7.75 2023 - April 1 5,000 5,000
7.375 2023 - October 1 20,250 20,250
7.10 2023 - November 1 12,000 12,000
7.30 2024 - April 1 10,000 10,000
Unamortized Discount (282) (371)
-------- --------
Total $136,633 $141,544
======== ========
(a) Redeemed on May 10, 2002.
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
Mason County, West
Virginia:
5.45% 2016 - December 1 $ 50,000 $ 50,000
Marshall County, West
Virginia:
5.45% 2014 - July 1 50,000 50,000
5.90% 2022 - April 1 35,000 35,000
6.85% 2022 - June 1 50,000 50,000
Ohio Air Quality
Development
5.15% 2026 - May 1 50,000 50,000
Unamortized Discount (1,660) (1,765)
Total $233,340 $233,235
======== ========
Under the terms of the installment purchase contracts, OPCo is required to pay
amounts
sufficient to enable the payment of interest on and the principal of (at stated
maturities and upon mandatory redemptions) related pollution control revenue
bonds issued to finance the construction of pollution control facilities at
certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ ------------------
6.75 2004 - July 1 $100,000 $100,000
7.00 2004 - July 1 75,000 75,000
6.73 2004 - November 1 48,000 48,000
6.24 2008 - December 4 37,225 37,225
7-3/8 2038 - June 30 140,000 140,000
Unamortized Discount (2,884) (3,263)
-------- --------
Total $397,341 $396,962
======== ========
Notes payable to parent company were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
4.336% 2003 - May 15 $ 60,000 $ 60,000
6.501% 2006 - May 15 240,000 240,000
-------- --------
Total $300,000 $300,000
======== ========
Junior debentures outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ -----------------
(a) 2025 - September 30 $ - $ 85,000
(a) 2027 - March 31 - 50,000
Unamortized Discount - (2,900)
-------- --------
Total $ - $132,100
======== ========
(a) Redeemed on July 24, 2002
At December 31, 2002 future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 149,665
2004 223,000
2005 -
2006 240,000
2007 -
Later Years 459,475
----------
Total Principal Amount 1,072,140
Unamortized Discount 4,826
----------
Total $1,067,314
==========
OHIO POWER COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------
The notes to OPCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to OPCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued
Operations Note 12
Asset Impairments and Investment Value Losses Note 13
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments
and Derivatives Note 17
Income Taxes Note 18
Supplementary Information Note 20
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Ohio Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Ohio Power Company as of December 31, 2002 and 2001, and the related
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Ohio Power Company as of December 31, 2002
and 2001, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
PUBLIC SERVICE COMPANY OF OKLAHOMA
AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Selected Consolidated Financial Data
- ------------------------------------
Year Ended December 31,
---------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 793,647 $957,000 $956,398 $749,390 $780,159
Operating Expenses 708,926 860,012 859,729 650,677 665,085
---------- -------- -------- -------- --------
Operating Income 84,721 96,988 96,669 98,713 115,074
Nonoperating Items,
Net (3,239) 20 8,974 946 (91)
Interest Charges 40,422 39,249 38,980 38,151 38,074
---------- -------- -------- -------- --------
Net Income 41,060 57,759 66,663 61,508 76,909
Preferred Stock Dividend
Requirements 213 213 212 212 213
Gain On Reacquired
Preferred Stock 1 - - - -
---------- -------- -------- -------- --------
Earnings Applicable to
Common Stock $ 40,848 $ 57,546 $ 66,451 $ 61,296 $ 76,696
========== ======== ======== ======== ========
December 31,
---------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $2,759,504 $2,695,099 $2,604,670 $2,459,705 $2,391,722
Accumulated Depreciation
and Amortization 1,239,855 1,184,443 1,150,253 1,114,255 1,082,081
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $1,519,649 $1,510,656 $1,454,417 $1,345,450 $1,309,641
========== ========== ========== ========== ==========
Total Assets $1,776,690 $1,748,911 $2,138,423 $1,524,846 $1,471,089
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 337,246 $ 337,246 $ 337,246 $ 337,246 $ 337,246
Accumulated Other Comprehensive
Income (Loss) (54,473) - - - -
Retained Earnings 116,474 142,994 137,688 139,237 142,941
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $ 399,247 $ 480,240 $ 474,934 $ 476,483 $ 480,187
========== ========== ========== ========== ==========
Cumulative Preferred
Stock:
Not Subject to
Mandatory Redemption $ 5,267 $ 5,267 $ 5,267 $ 5,270 $ 5,271
========== ========== ========== ========== ==========
Preferred Securities of
Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 75,000
========== ========== ========== ========== ==========
Long-term Debt (a) $ 545,437 $ 451,129 $ 470,822 $ 384,516 $ 384,064
========== ========== ========== ========== ==========
Total Capitalization and
Liabilities $1,776,690 $1,748,911 $2,138,423 $1,524,846 $1,471,089
========== ========== ========== ========== ==========
(a) Including portion due within one year.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------
Public Service Company of Oklahoma (PSO) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO
also sells electric power at wholesale to other utilities, municipalities and
rural electric cooperatives.
Wholesale power marketing activities are conducted on PSO's behalf by AEPSC.
PSO, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.
Results of Operations
- ---------------------
In 2002, Net Income decreased by $17 million or 29% primarily resulting from
reduced wholesale margins and increased depreciation expense.
Changes in Operating Revenues
- -----------------------------
Operating revenues decreased in 2002 as a result of reduced wholesale margins, a
decline in fuel recovery revenue and decreases due to the interchange cost
reconstruction (ICR) adjustments (see Note 6).
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Wholesale Electricity* $(149.7) (23)
Energy Delivery* 13.6 5
Sales to AEP Affiliates (27.3) (74)
-------
Total Operating Revenues $(163.4) (17)
=======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Changes in Operating Expenses
- -----------------------------
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
Amount %
------ -
Fuel $(215.3) (47)
Purchased Power:
Wholesale Electricity 23.3 96
AEP Affiliates 45.7 104
Other Operation (4.1) (3)
Maintenance 1.9 4
Depreciation and
Amortization 5.6 7
Taxes Other Than
Income Taxes 2.1 7
Income Taxes (10.3) (30)
-------- ---
Total $(151.1) (18)
======= ===
N.M. = Not Meaningful
The decrease in Fuel expense in 2002 was primarily due to lower market prices
for natural gas and fuel oil, and deferral of underrecovered fuel costs due to
the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and
to the amortization of previously overrecovered fuel costs.
The increase in Electricity Marketing Purchased Power expense in 2002 resulted
mainly from ICR adjustments (see Note 6), partially offset by a decrease in
energy prices.
The increase in the AEP Affiliates Purchased Power expense in 2002 resulted
mainly from the ICR adjustments (see Note 6).
Other Operation expense decreased in 2002 primarily due to lower transmission
expenses and decreased factoring expenses due to reduced revenues.
Maintenance expense increased, in 2002 largely as a result of increased expenses
to repair damage to overhead lines caused by a winter storm in 2002.
Depreciation and Amortization expense increased in 2002 primarily due to the
additional depreciable capitalized costs involved in repowering Northeast
Station Units 1 & 2 completed in 2001.
Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in
ad valorem taxes.
Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.
Other Changes
- -------------
Nonoperating Expenses increased primarily due to the write-down of certain
non-utility investments in 2002.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Income
- ---------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $508,661 $658,352 $696,626
Energy Delivery 275,547 261,877 245,124
Sales to AEP Affiliates 9,439 36,771 14,648
-------- -------- --------
TOTAL OPERATING REVENUES 793,647 957,000 956,398
-------- -------- --------
OPERATING EXPENSES:
Fuel 246,199 461,470 402,933
Purchased Power:
Wholesale Electricity 47,507 24,187 88,088
AEP Affiliates 89,454 43,758 60,788
Other Operation 133,538 137,678 121,697
Maintenance 48,060 46,188 45,858
Depreciation and Amortization 85,896 80,245 76,418
Taxes Other Than Income Taxes 34,077 31,973 28,688
Income Taxes 24,195 34,513 35,259
-------- -------- --------
TOTAL OPERATING EXPENSES 708,926 860,012 859,729
-------- -------- --------
OPERATING INCOME 84,721 96,988 96,669
NONOPERATING INCOME 1,920 2,112 8,807
NONOPERATING EXPENSES 6,971 1,740 1,139
NONOPERATING INCOME TAX EXPENSE (CREDIT) (1,812) 352 (1,306)
INTEREST CHARGES 40,422 39,249 38,980
-------- -------- --------
NET INCOME 41,060 57,759 66,663
GAIN ON REACQUIRED PREFERRED STOCK 1 - -
LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 213 213 212
-------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 40,848 $ 57,546 $ 66,451
======== ======== ========
Consolidated Statements of Comprehensive Income
- -----------------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $ 41,060 $57,759 $66,663
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (42) - -
Minimum Pension Liability (54,431) - -
-------- ------- -------
COMPREHENSIVE INCOME (LOSS) $(13,413) $57,759 $66,663
======== ======= =======
The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes
to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Retained Earnings
- --------------------------------------------
Year Ended December 31,
---------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $142,994 $137,688 $139,237
NET INCOME 41,060 57,759 66,663
DEDUCTIONS
Capital Stock Gains (1) - -
Cash Dividends Declared:
Common Stock 67,368 52,240 68,000
Preferred Stock 213 213 212
-------- -------- --------
BALANCE AT END OF PERIOD $116,474 $142,994 $137,688
======== ======== ========
The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes
to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Balance Sheets
- ---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,040,520 $1,034,711
Transmission 432,846 427,110
Distribution 990,947 972,806
General 206,747 203,572
Construction Work in Progress 88,444 56,900
---------- ----------
Total Electric Utility Plant 2,759,504 2,695,099
Accumulated Depreciation and Amortization 1,239,855 1,184,443
---------- ----------
NET ELECTRIC UTILITY PLANT 1,519,649 1,510,656
---------- ----------
OTHER PROPERTY AND INVESTMENTS 5,383 41,020
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4,481 21,354
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 16,774 5,795
Accounts Receivable:
Customers 31,687 31,144
Affiliated Companies 14,139 10,905
Allowance for Uncollectible Accounts (84) (44)
Fuel Inventory 19,973 21,559
Materials and Supplies 37,375 36,785
Under-recovered Fuel Costs 76,470 756
Energy Trading and Derivative Contracts 3,841 26,259
Prepayments and Other 2,735 2,368
---------- ----------
TOTAL CURRENT ASSETS 202,910 135,527
---------- ----------
REGULATORY ASSETS 26,150 35,064
---------- ----------
DEFERRED CHARGES 18,117 5,290
---------- ----------
TOTAL ASSETS $1,776,690 $1,748,911
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $ 157,230 $ 157,230
Paid-in Capital 180,016 180,016
Accumulated Other Comprehensive Income (Loss) (54,473) -
Retained Earnings 116,474 142,994
---------- ----------
Total Common Shareholder's Equity 399,247 480,240
---------- ----------
Cumulative Preferred Stock Not Subject
to Mandatory Redemption 5,267 5,267
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 445,437 345,129
---------- ----------
TOTAL CAPITALIZATION 924,951 905,636
---------- ----------
OTHER NONCURRENT LIABILITIES 54,761 7,263
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 100,000 106,000
Advances from Affiliates 86,105 123,087
Accounts Payable - General 61,169 72,759
Accounts Payable - Affiliated Companies 78,076 40,857
Customer Deposits 21,789 21,041
Over-Recovered Fuel Costs - 9,476
Taxes Accrued 6,854 18,150
Interest Accrued 6,979 7,298
Energy Trading and Derivative Contracts 3,260 31,718
Other 24,957 12,216
---------- ----------
TOTAL CURRENT LIABILITIES 389,189 442,602
---------- ----------
DEFERRED INCOME TAXES 341,396 296,877
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 32,201 33,992
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 32,611 49,080
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,581 13,461
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $1,776,690 $1,748,911
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Cash Flows
- -------------------------------------
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 41,060 $ 57,759 $ 66,663
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and Amortization 85,896 80,245 76,418
Deferred Income Taxes 75,659 (17,751) 25,453
Deferred Investment Tax Credits (1,791) (1,791) (1,791)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (3,737) 21,405 (28,826)
Fuel, Materials and Supplies 996 (589) 677
Other Property and Investments (419) (2,809) 7,994
Accounts Payable 25,629 (55,319) 89,330
Taxes Accrued (11,296) 16,491 (16,821)
Fuel Recovery (85,190) 51,987 (36,798)
Transmission Coordination Agreement Settlement - - (15,063)
Changes in Other Assets 2,215 (9,120) 4,482
Changes in Other Liabilities (6,928) 9,351 (6,103)
--------- --------- ---------
Net Cash From Operating Activities 122,094 149,859 165,615
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (89,365) (124,520) (176,851)
Proceeds from Sale of Property 963 - -
Other Items - (359) -
--------- --------- ---------
Net Cash Used For
Investing Activities (88,402) (124,879) (176,851)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 187,850 - 105,625
Retirement of Long-term Debt (106,000) (20,000) (20,000)
Change in Advances From Affiliates (net) (36,982) 41,967 1,951
Dividends Paid on Common Stock (67,368) (52,240) (68,000)
Dividends Paid on Cumulative Preferred Stock (213) (213) (212)
--------- --------- ---------
Net Cash From (used For)
Financing Activities (22,713) (30,486) 19,364
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 10,979 (5,506) 8,128
Cash and Cash Equivalents January 1 5,795 11,301 3,173
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 16,774 $ 5,795 $ 11,301
========= ========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $38,620,000,
$38,250,000 and $33,732,000 and for income taxes was ($38,943,000),
$38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Capitalization
- -----------------------------------------
December 31,
------------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 399,247 $480,240
--------- --------
PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000,
redeemable at the option of PSO upon 30 days notice.
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
- ------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption:
4.00% $105.75 6 - 25 44,600 4,460 4,460
4.24% 103.19 - - - 8,069 807 807
--------- ---------
5,267 5,267
--------- ---------
TRUST PREFERRED SECURITIES
PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely Junior Subordinated Debentures of PSO, 8.00%,
due April 30, 2037 75,000 75,000
--------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 298,079 297,772
Installment Purchase Contracts 47,358 47,357
Senior Unsecured Notes 200,000 106,000
Less Portion Due Within One Year (100,000) (106,000)
--------- --------
Long-term Debt Excluding Portion Due Within One Year 445,437 345,129
--------- --------
TOTAL CAPITALIZATION $ 924,951 $905,636
========= ========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6.25 2003 - April 1 $ 35,000 $ 35,000
7.25 2003 - July 1 65,000 65,000
7.38 2004 - December 1 50,000 50,000
6.50 2005 - June 1 50,000 50,000
7.38 2023 - April 1 100,000 100,000
Unamortized Discount (1,921) (2,228)
-------- --------
$298,079 $297,772
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
Oklahoma Environmental
Finance Authority (OEFA):
5.90 2007 - December 1 $ 1,000 $ 1,000
Oklahoma Development
Finance Authority (ODFA):
4.875 2014 - June 1 33,700 33,700
Red River Authority
of Texas:
6.00 2020 - June 1 12,660 12,660
Unamortized Discount (2) (3)
------- -------
Total $47,358 $47,357
======= =======
Under the terms of the installment purchase contracts, PSO is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
(a) 2002 - November 21 $ - $106,000
(b) 2032 - December 31 200,000 -
-------- --------
TOTAL $200,000 $106,000
======== ========
(a) A floating interest rate is determined monthly. The rate on December 31,
2001 was $2.775%.
(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.
At December 31, 2002, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $100,000
2004 50,000
2005 50,000
2006 -
2007 1,000
Later Years 346,360
--------
Total Principal Amount 547,360
Unamortized Discount (1,923)
--------
Total $545,437
========
See Note 25 for discussion of the Trust Preferred Securities issued by a wholly
owned statutory business trust of PSO (see Note 25).
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------
The notes to PSO's consolidated financial statements are combined with the notes
to financial statements for AEP and its other subsidiary registrants. Listed
below are the combined notes that apply to PSO. The combined footnotes begin on
page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Public Service Company of Oklahoma and
subsidiary as of December 31, 2002 and 2001, and the related consolidated
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Public Service Company of Oklahoma
and subsidiary as of December 31, 2002 and 2001, and the results of their
operations and their cash flows each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
SOUTHWESTERN ELECTRIC POWER COMPANY
AND SUBSIDIARIES
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
Year Ended December 31,
------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,084,720 $1,101,326 $1,118,274 $ 971,527 $ 952,952
Operating Expenses 942,251 955,119 989,996 824,465 802,274
---------- ---------- ---------- ---------- ----------
Operating Income 142,469 146,207 128,278 147,062 150,678
Nonoperating Items, Net (309) 741 3,851 (1,965) 2,451
Interest Charges 59,168 57,581 59,457 58,892 55,135
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 82,992 89,367 72,672 86,205 97,994
Extraordinary Loss - - - (3,011) -
---------- ---------- ---------- ---------- ----------
Net Income 82,992 89,367 72,672 83,194 97,994
Preferred Stock Dividend
Requirements 229 229 229 229 705
Loss on
Reacquired Preferred
Stock - - - - (856)
---------- ---------- ---------- ---------- ----------
Earnings Applicable to
Common Stock $ 82,763 $ 89,138 $ 72,443 $ 82,965 $ 96,433
========== ======== ======== ========== ==========
December 31,
------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,596,174 $3,460,764 $3,319,024 $3,231,431 $3,157,911
Accumulated Depreciation
and Amortization 1,697,338 1,550,618 1,457,005 1,384,242 1,317,057
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $1,898,836 $1,910,146 $1,862,019 $1,847,189 $1,840,854
========== ========== ========== ========== ==========
Total Assets $2,208,675 $2,300,676 $2,658,389 $2,106,762 $2,082,258
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 380,663 $ 380,663 $ 380,663 $ 380,663 $ 380,663
Accumulated Other Comprehensive
Income (Loss) (53,683) - - - -
Retained Earnings 334,789 308,915 293,989 283,546 296,581
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $ 661,769 $ 689,578 $ 674,652 $ 664,209 $ 677,244
========== ========== ========== ========== ==========
Preferred Stock $ 4,701 $ 4,701 $ 4,701 $ 4,703 $ 4,704
========== ========== ========= ========== ==========
Trust Preferred
Securities $ 110,000 $ 110,000 $ 110,000 $ 110,000 $ 110,000
========== ========== ========== ========== ==========
Long-term Debt (a) $ 693,448 $ 645,283 $ 645,963 $ 541,568 $ 587,673
========== ========== ========== ========== ==========
Total Capitalization and Liabilities $2,208,675 $2,300,676 $2,658,389 $2,106,762 $2,082,258
========== ========== ========== ========== ==========
(a) Including portion due within one year.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------
Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 437,000 retail customers in northeastern Texas, northwestern
Louisiana and western Arkansas. SWEPCo also sells electric power at wholesale to
other utilities, municipalities and rural electric cooperatives.
Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC.
SWEPCo, along with the other AEP electric operating subsidiaries, shares in
AEP's electric power transactions with other utility systems and power
marketers.
Results of Operations
- ---------------------
In 2002, Net Income decreased $6.4 million or 7% primarily resulting from
reduced margins. In 2001, Net Income increased $16.7 million or 23% resulting
primarily from the favorable impact of our sharing in AEP's power marketing
activities for a full year.
Changes in Operating Revenues
- -----------------------------
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
2002 2001
---- ----
Amount % Amount %
------ - ------ -
Wholesale
Electricity* $(25) (4) $(21) (3)
Energy Delivery* 15 5 (12) (3)
Sales to AEP
Affiliates (7) (9) 16 26
---- ----
Total
Operating
Revenues $(17) (2) $(17) (2)
==== ====
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Operating Revenues decreased 2% for 2002 primarily due to decreased fuel
revenues offset in part by the addition of the Dolet Hills mining operation
($12.6 million) and the positive impact of the interchange cost reconstruction
(ICR) adjustments (see Note 6).
In 2001, Operating Revenues decreased $17 million or 2% resulting from
unfavorable wholesale marketing and trading conditions.
Changes in Operating Expenses
- -----------------------------
Increase (Decrease)
From Previous Year
------------------
(dollars in millions)
2002 2001
---- ----
Amount % Amount %
------ - ------ -
Fuel $(69) (15) $(41) (8)
Purchased
Power:
Wholesale
Electricity 26 143 (40) (69)
AEP
Affiliates 26 165 2 19
Other Operation 18 10 12 7
Maintenance (8) (10) - (1)
Depreciation
and
Amortization 3 3 15 14
Taxes Other
Than
Income Taxes (1) (1) 2 4
Income Taxes (8) (20) 16 60
---- ----
Total $(13) (1) $(34) (4)
==== ====
Fuel expense decreased in 2002 due to a reduction in MWH generated and a
decrease in the cost of fuel, primarily natural gas.
Fuel expense decreased in 2001 from lower natural gas prices and a mild summer
resulting in a reduction in generation.
In 2002, Purchased Power increased primarily due to the impact of ICR
adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was
mainly due to reduced prices caused by decreased electricity demand.
The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused
Other Operation expense to increase in 2002 by $4.3 million. Other Operation
expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other
Operation expense increased also as a result of the Dolet Hills mining operation
in June 2001.
The 10% decrease in Maintenance expense in 2002 is primarily a result of higher
storm and tree trimming related expenses in 2001.
The increase in Depreciation and Amortization expense in 2002 is primarily due
to the addition of Dolet Hills in June 2001, which added $3.0 million of
additional expense in 2002. Depreciation and Amortization expense increased in
2001 due primarily to an increase in excess earnings accruals under the Texas
restructuring legislation and the acquisition of Dolet Hills mining operation.
In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income.
In 2001, the increase in income tax expense was primarily due to an increase in
pre-tax income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
Year Ended December 31,
------------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING REVENUES:
Wholesale Electricity $ 664,185 $ 689,085 $ 710,200
Energy Delivery 348,236 333,004 344,950
Sales to AEP Affiliates 72,299 79,237 63,124
---------- ---------- ----------
TOTAL OPERATING REVENUES 1,084,720 1,101,326 1,118,274
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 388,334 457,613 498,805
Purchased Power:
Wholesale Electricity 44,119 18,164 58,518
AEP Affiliates 42,022 15,858 13,338
Other Operation 189,024 171,314 159,459
Maintenance 66,855 74,677 75,123
Depreciation and Amortization 122,969 119,543 104,679
Taxes Other Than Income Taxes 55,232 55,834 53,830
Income Taxes 33,696 42,116 26,244
---------- ---------- ----------
TOTAL OPERATING EXPENSES 942,251 955,119 989,996
---------- ---------- ----------
OPERATING INCOME 142,469 146,207 128,278
NONOPERATING INCOME 3,260 4,512 5,487
NONOPERATING EXPENSES 1,797 3,229 3,112
NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,772 542 (1,476)
INTEREST CHARGES 59,168 57,581 59,457
---------- ---------- ----------
NET INCOME 82,992 89,367 72,672
PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 82,763 $ 89,138 $ 72,443
========== ========== ==========
Consolidated Statements of Comprehensive Income
- -----------------------------------------------
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
NET INCOME $82,992 $89,367 $72,672
OTHER COMPREHENSIVE INCOME (LOSS):
Cash Flow Power Hedges (48) - -
Minimum Pension Liability (53,635) - -
------- ------- -------
COMPREHENSIVE INCOME $29,309 $89,367 $72,672
======= ======= =======
The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See
Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------
Year Ended December 31,
----------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $308,915 $293,989 $283,546
NET INCOME 82,992 89,367 72,672
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 56,889 74,212 62,000
Preferred Stock 229 229 229
-------- -------- --------
BALANCE AT END OF PERIOD $334,789 $308,915 $293,989
======== ======== ========
The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See
Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,503,722 $1,429,356
Transmission 575,003 538,749
Distribution 1,063,564 1,042,523
General 378,130 376,016
Construction Work in Progress 75,755 74,120
---------- ----------
Total Electric Utility Plant 3,596,174 3,460,764
Accumulated Depreciation and Amortization 1,697,338 1,550,618
---------- ----------
NET ELECTRIC UTILITY PLANT 1,898,836 1,910,146
---------- ----------
OTHER PROPERTY AND INVESTMENTS 5,978 43,000
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 5,119 24,508
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 2,069 5,415
Accounts Receivable:
Customers 62,359 43,133
Affiliated Companies 19,253 12,069
Allowance for Uncollectible Accounts (2,128) (89)
Fuel Inventory 61,741 52,212
Materials and Supplies 33,539 32,527
Under-recovered Fuel Costs 2,865 8,839
Energy Trading and Derivative Contracts 4,388 30,139
Prepayments and Other 17,851 18,716
---------- ----------
TOTAL CURRENT ASSETS 201,937 202,961
---------- ----------
REGULATORY ASSETS 49,233 52,308
---------- ----------
DEFERRED CHARGES 47,572 67,753
---------- ----------
TOTAL ASSETS $2,208,675 $2,300,676
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
December 31,
-----------
2002 2001
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $ 135,660 $ 135,660
Paid-in Capital 245,003 245,003
Accumulated Other Comprehensive Income (Loss) (53,683) -
Retained Earnings 334,789 308,915
---------- ----------
Total Common Shareholder's Equity 661,769 689,578
Preferred Stock 4,701 4,701
SWEPCo-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of SWEPCo 110,000 110,000
Long-term Debt 637,853 494,688
---------- ----------
TOTAL CAPITALIZATION 1,414,323 1,298,967
---------- ----------
OTHER NONCURRENT LIABILITIES 78,494 40,109
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 55,595 150,595
Advances from Affiliates, net 23,239 117,367
Accounts Payable - General 62,139 71,810
Accounts Payable - Affiliated Companies 58,773 37,469
Customer Deposits 20,110 19,880
Taxes Accrued 19,081 36,522
Interest Accrued 17,051 13,027
Energy Trading and Derivative Contracts 3,724 36,297
Over-recovered Fuel 17,226 5,487
Other 34,565 26,074
---------- ----------
TOTAL CURRENT LIABILITIES 311,503 514,528
---------- ----------
DEFERRED INCOME TAXES 341,064 369,781
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 44,190 48,714
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 13,127
---------- ----------
LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,806 15,450
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL CAPITALIZATION AND LIABILITIES $2,208,675 $2,300,676
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
Year Ended December 31,
--------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 82,992 $ 89,367 $ 72,672
Adjustments to Reconcile Net Income to Net Cash Flows From Operating
Activities:
Depreciation and Amortization 122,969 119,543 104,679
Deferred Income Taxes (3,134) (31,396) 14,653
Deferred Investment Tax Credits (4,524) (4,453) (4,482)
Mark-to-Market Energy Trading and Derivative Contracts (1,151) (10,695) 7,795
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (24,371) (11,447) (1,254)
Fuel, Materials and Supplies (10,541) (19,578) 22,103
Accounts Payable 11,633 (34,489) 43,962
Taxes Accrued (17,441) 25,298 (13,150)
Transmission Coordination Agreement Settlement - - (24,406)
Fuel Recovery 17,713 34,423 (38,357)
Change in Other Assets 24,257 1,323 54,414
Change in Other Liabilities 12,161 11,714 (37,001)
--------- --------- ---------
Net Cash Flows From Operating Activities 210,563 169,610 201,628
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (111,775) (111,725) (120,671)
Purchase of Dolet Hills Mining Operations - (85,716) -
Other 1,134 (411) 446
--------- --------- ---------
Net Cash Flows Used For
Investing Activities (110,641) (197,852) (120,225)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 198,573 - 149,360
Redemption of Preferred Stock - - (1)
Retirement of Long-term Debt (150,595) (595) (45,595)
Change in Advances From Affiliates (net) (94,128) 106,786 (124,074)
Dividends Paid on Common Stock (56,889) (74,212) (62,000)
Dividends Paid on Cumulative Preferred Stock (229) (229) (229)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (103,268) 31,750 (82,539)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (3,346) 3,508 (1,136)
Cash and Cash Equivalents January 1 5,415 1,907 3,043
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 2,069 $ 5,415 $ 1,907
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000
and $51,111,000 and for income taxes was $60,451,000, $49,901,000 and
$27,994,000 in 2002, 2001, and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------
December 31,
-----------
2002 2001
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 661,769 $ 689,578
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 1,860,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2002 Year Ended December 31, December 31, 2002
- ------ ------------ ---------------------------- -----------------
2002 2001 2000
---- ---- ----
Not Subject to Mandatory Redemption:
4.28% $103.90 - - - 7,386 740 740
4.65% $102.75 - - - 1,907 190 190
5.00% $109.00 - - 12 37,715 3,771 3,771
---------- ----------
4,701 4,701
---------- ----------
TRUST PREFERRED SECURITIES
SWEPCo-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of SWEPCo, 7.875%,
due April 30, 2037 110,000 110,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 315,420 315,449
Installment Purchase Contracts 179,183 179,834
Senior Unsecured Notes 198,845 150,000
Less Portion Due Within One Year (55,595) (150,595)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 637,853 494,688
---------- ----------
TOTAL CAPITALIZATION $1,414,323 $1,298,967
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------
First mortgage bonds outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
6-5/8 2003 - February 1 $ 55,000 $ 55,000
7-3/4 2004 - June 1 40,000 40,000
6.20 2006 - November 1 5,505 5,650
6.20 2006 - November 1 1,000 1,000
7.00 2007 - September 1 90,000 90,000
7-1/4 2023 - July 1 45,000 45,000
6-7/8 2025 - October 1 80,000 80,000
Unamortized Discount (1,085) (1,201)
-------- --------
$315,420 $315,449
======== ========
First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
DeSoto County:
7.60 2019 - January 1 $ 53,500 $ 53,500
Sabine:
6.10 2018 - April 1 81,700 81,700
Titus County:
6.90 2004 - November 1 12,290 12,290
6.00 2008 - January 1 12,620 13,070
8.20 2011 - August 1 17,125 17,125
Unamortized Premium 1,948 2,149
-------- --------
$179,183 $179,834
======== ========
Under the terms of the installment purchase contracts, SWEPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
-----------
2002 2001
---- ----
(in thousands)
% Rate Due
- ------ ------------------
4.50 2005 - July 1 $200,000 $ -
(a) 2002 - March 1 - 150,000
Unamortized Discount (1,155) -
-------- --------
$198,845 $150,000
======== ========
(a)A floating interest rate is determined monthly. The rate on December 31, 2001
was 2.311%.
At December 31, 2002 future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2003 $ 55,595
2004 52,885
2005 200,595
2006 6,520
2007 90,450
Later Years 287,695
--------
Total Principal Amount 693,740
Unamortized Discount (292)
--------
Total $693,448
========
See Note 25 for discussion of Trust Preferred Securities issued by a
wholly-owned statutory business trust of SWEPCo.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------
The notes to SWEPCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to SWEPCo. The combined footnotes
begin on page L-1.
Combined
Footnote
Reference
---------
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Goodwill and Other Intangible Assets Note 3
Merger Note 4
Rate Matters Note 6
Effects of Regulation Note 7
Customer Choice and Industry Restructuring Note 8
Commitments and Contingencies Note 9
Guarantees Note 10
Sustained Earnings Improvement Initiative Note 11
Acquisitions, Dispositions and Discontinued Operations Note 12
Benefit Plans Note 14
Business Segments Note 16
Risk Management, Financial Instruments and Derivatives Note 17
Income Taxes Note 18
Leases Note 22
Lines of Credit and Sale of Receivables Note 23
Unaudited Quarterly Financial Information Note 24
Trust Preferred Securities Note 25
Jointly Owned Electric Utility Plant Note 28
Related Party Transactions Note 29
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Southwestern Electric Power Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southwestern Electric Power Company and
subsidiaries as of December 31, 2002 and 2001, and the related consolidated
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Southwestern Electric Power Company
and subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003
COMBINED NOTES TO FINANCIAL STATEMENTS
Index to Combined Notes to Financial Statements
The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list of footnotes shows the
registrant to which they apply:
1. Significant Accounting Policies AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
2. Extraordinary Items and AEP, APCo, CSPCo, OPCo, SWEPCo,
Cumulative Effect TCC, TNC
3. Goodwill and Other Intangible Assets AEP, SWEPCo
4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC,
TNC
5. Nuclear Plant Restart AEP, I&M
6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC
7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
8. Customer Choice and Industry AEP, APCo, CSPCo, I&M, OPCo, PSO,
Restructuring SWEPCo, TCC, TNC
9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
11. Sustained Earnings Improvement AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
Initiative OPCo, PSO, SWEPCo, TCC, TNC
12. Acquisitions, Dispositions and AEP, OPCo, SWEPCo, TCC, TNC
Discontinued Operations
13. Asset Impairments and Investment AEP, APCo, CSPCo, I&M, KPCo, OPCo,
Value Losses TCC, TNC
14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, TCC, TNC
15. Stock-Based Compensation AEP
16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
17. Risk Management, Financial AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
Instruments and Derivatives OPCo, PSO, SWEPCo, TCC, TNC
18. Income Taxes AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
19. Basic and Diluted Earnings Per Share AEP
20. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo
21. Power and Distribution Projects AEP
22. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC, TNC
23. Lines of Credit and Sale AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
of Receivables OPCo, PSO, SWEPCo, TCC, TNC
24. Unaudited Quarterly Financial AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
Information OPCo, PSO, SWEPCo, TCC, TNC
25. Trust Preferred Securities AEP, PSO, SWEPCo, TCC
26. Minority Interest in Finance AEP
Subsidiary
27. Equity Units AEP
28. Jointly Owned Electric Utility Plant CSPCo, PSO, SWEPCo, TCC, TNC
29. Related Party Transactions AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, TCC, TNC
30. Subsequent Events (Unaudited) AEP
1. Significant Accounting Policies:
Business Operations - AEP's (the Company's) principal business conducted by its
eleven domestic electric utility operating companies is the generation,
transmission and distribution of electric power. Nine of AEP's eleven domestic
electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC, TNC, are SEC registrants. AEGCo is a domestic generating company
wholly-owned by AEP that is an SEC registrant. These companies are subject to
regulation by the FERC under the Federal Power Act and follow the Uniform System
of Accounts prescribed by FERC. They are subject to further regulation with
regard to rates and other matters by state regulatory commissions.
AEP also engages in wholesale marketing and trading of electricity, natural gas
and to a lesser extent, other commodities in the United States and Europe. In
addition, the Company's domestic operations include non-regulated independent
power and cogeneration facilities, coal mining and intra-state midstream natural
gas operations in Louisiana and Texas.
International operations include supply of electricity and other non-regulated
power generation projects in the United Kingdom, and to a lesser extent in
Mexico, Australia, China and the Pacific Rim region. These operations are either
wholly-owned or partially-owned by various AEP subsidiaries. We also maintained
operations in Brazil through the fourth quarter of 2002. See Note 13 for
discussion of impaired investments and assets held for sale.
The Company also operates domestic barging operations, provides various energy
related services and furnishes communications related services domestically. See
Note 13 for further discussion of changes in our communications related business
and other business operations announced in 2002.
Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The
rates charged by the domestic utility subsidiaries are approved by the FERC and
the state utility commissions. The FERC regulates wholesale electricity
operations and transmission rates and the state commissions regulate retail
rates. The prices charged by foreign subsidiaries located in China, Mexico and
Brazil are regulated by the authorities of that country and are generally
subject to price controls.
Principles of Consolidation - AEP's consolidated financial statements include
AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated
with their wholly-owned or substantially controlled subsidiaries. The
consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC
include the registrant and its wholly-owned subsidiaries. Significant
intercompany items are eliminated in consolidation. Equity investments not
substantially controlled that are 50% or less owned are accounted for using the
equity method with their equity earnings included in Other Income for AEP and
nonoperating income for the registrant subsidiaries.
Basis of Accounting - As the owner of cost-based rate-regulated electric public
utility companies, AEP Co., Inc.'s consolidated financial statements reflect the
actions of regulators that result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate-regulated. In
accordance with SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory liabilities
(future revenue reductions or refunds) are recorded to reflect the economic
effects of regulation by matching expenses with their recovery through regulated
revenues. Application of SFAS 71 for the generation portion of the business was
discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in
Virginia and West Virginia by APCo in June 2000, in Texas by TCC, TNC, and
SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note
8, "Customer Choice and Industry Restructuring" for additional information.
Use of Estimates - The preparation of these financial statements in conformity
with generally accepted accounting principles necessarily includes the use of
estimates and assumptions by management. Actual results could differ from those
estimates.
Property, Plant and Equipment - Domestic electric utility property, plant and
equipment are stated at original cost of the acquirer. Property, plant and
equipment of the non-regulated operations and other investments are stated at
their fair market value at acquisition plus the original cost of property
acquired or constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. For cost-based
rate-regulated operations, retirements from the plant accounts and associated
removal costs, net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overhead incurred to operate and maintain plant
are included in operating expenses. Plants are tested for impairment as required
under SFAS 144. See Note 13.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- - AFUDC is a noncash, nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated electric
utility plant. It represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 2002, 2001 and
2000 were not significant. Effective with the discontinuance of SFAS 71
regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas,
Virginia, West Virginia and other non-regulated operations, interest is
capitalized during construction in accordance with SFAS 34, "Capitalization of
Interest Costs." The amounts of interest capitalized were not material in 2002,
2001, and 2000.
Depreciation, Depletion and Amortization - Depreciation of property, plant and
equipment is provided on a straight-line basis over the estimated useful lives
of property, other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:
Annual Composite
Functional Class Depreciation Rates
of Property Ranges
- ---------------- ------------------
2002
----
Production:
Steam-Nuclear 2.5% to 3.4%
Steam-Fossil-Fired 2.6% to 4.5%
Hydroelectric- Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.0%
Distribution 3.3% to 4.2%
Other 1.8% to 9.9%
Annual Composite
Functional Class Depreciation Rates
of Property Ranges
- ---------------- ------------------
2001
----
Production:
Steam-Nuclear 2.5% to 3.4%
Steam-Fossil-Fired 2.5% to 4.5%
Hydroelectric- Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.1%
Distribution 2.7% to 4.2%
Other 1.8% to 15.0%
Annual Composite
Functional Class Depreciation Rates
of Property Ranges
- ---------------- ------------------
2000
----
Production:
Steam-Nuclear 2.8% to 3.4%
Steam-Fossil-Fired 2.3% to 4.5%
Hydroelectric- Conventional
and Pumped Storage 1.9% to 3.4%
Transmission 1.7% to 3.1%
Distribution 3.3% to 4.2%
Other 2.5% to 7.3%
The following table provides the annual composite depreciation rates generally
used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which
were as follows:
Nuclear Steam Hydro Transmission Distribution General
------- ----- ----- ------------ ------------ -------
AEGCo - % 3.5% - % - % - % 2.8%
APCo - 3.4 2.9 2.2 3.3 3.1
CSPCo - 3.2 - 2.3 3.6 3.2
I&M 3.4 4.5 3.4 1.9 4.2 3.8
KPCo - 3.8 - 1.7 3.5 2.5
OPCo - 3.4 2.7 2.3 4.0 2.7
PSO - 2.7 - 2.3 3.4 6.3
SWEPCo - 3.4 - 2.7 3.6 4.7
TCC 2.5 2.6 1.9 2.3 3.5 4.0
TNC - 2.8 - 3.1 3.3 6.8
Depreciation, depletion and amortization of coal-mining assets is provided over
each asset's estimated useful life or the estimated life of the mine, whichever
is shorter, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used to amortize
coal rights and mine development costs based on estimated recoverable tonnages.
These costs are included in the cost of coal charged to fuel expense for coal
used by utility operations. Current average amortization rates are $0.32 per ton
in 2002, $3.46 per ton in 2001 and $5.07 per ton in 2000. In 2001, an AEP
subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions,
Dispositions and Discontinued Operations for further discussion of the changes
in our coal investments leading to the decline in amortization rates in 2002.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash
investments with original maturities of three months or less.
Inventory - Except for PSO, TCC and TNC, the regulated domestic utility
companies value fossil fuel inventories using a weighted average cost method.
PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For
those domestic utilities whose generation is unregulated, inventory of coal and
oil is carried at the lower of cost or market. Coal mine inventories are also
carried at the lower of cost or market. Materials and supplies inventories are
carried at average cost.
Non-trading gas inventory is carried at the lower of cost or market. In
compliance with EITF 02-03 as described in the New Accounting Pronouncements
section of Note 1, natural gas inventories held in connection with trading
operations at October 25, 2002 continued to be carried at fair value until
December 31, 2002, and inventory purchased from October 26 through December 31,
2002 was carried at the lower of cost or market. Effective January 1, 2003, all
natural gas inventories held in connection with trading operations will be
adjusted to the historical cost basis and carried at the lower of cost or
market. We estimate the adjustment in January 2003 will decrease the value of
natural gas inventories held in connection with trading operations by
approximately $39 million. This change will be accounted for as a cumulative
effect of a change in accounting principle.
Accounts Receivable - AEP Credit, Inc. factors accounts receivable for certain
of the domestic utility subsidiaries and, until the first quarter of 2002,
factored accounts receivable for certain non-affiliated utilities. On December
31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement with a
group of banks and commercial paper conduits. This transaction constitutes a
sale of receivables in accordance with SFAS 140, allowing the receivables to be
taken off of the company's balance sheet. See Note 23 for further details.
Foreign Currency Translation - The financial statements of subsidiaries outside
the U.S. which are included in AEP's consolidated financial statements are
measured using the local currency as the functional currency and translated into
U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets
and liabilities are translated to U.S. dollars at year-end rates of exchange and
revenues and expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss adjustments are recorded
in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The
non-cash impact of the changes in exchange rates on cash, resulting from the
translation of items at different exchange rates, is shown on AEP's Consolidated
Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual
currency transaction gains and losses are recorded in income.
Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the
fuel is burned. Where applicable under governing state regulatory commission
retail rate orders, fuel cost over or under-recoveries are deferred as
regulatory liabilities or regulatory assets in accordance with SFAS 71. These
deferrals generally are amortized when refunded or billed to customers in later
months with the regulator's review and approval. The amount of deferred fuel
costs under fuel clauses for AEP was $143 million at December 31, 2002 and $139
million at December 31, 2001. See Note 7 "Effects of Regulation".
We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of
Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for
APCo. Where fuel clauses have been eliminated due to the transition to market
pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective
January 1, 2002) changes in fuel costs impact earnings. In other state
jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have
been frozen or suspended for a period of years, fuel cost changes also impact
earnings. This is also true for certain of AEP's Independent Power Producer
generating units that do not have long-term contracts for their fuel supply. See
Note 6, "Rate Matters" and Note 8, "Customer Choice and Industry Restructuring"
for further information about fuel recovery.
Revenue Recognition -
Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo,
TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide currently for refunds to
customers that have not yet been made.
When regulatory assets are probable of recovery through regulated rates, we
record them as assets on the balance sheet. We test for probability of recovery
whenever new events occur, for example a regulatory commission order or passage
of new legislation. If we determine that recovery of a regulatory asset is no
longer probable, we write off that regulatory asset as a charge against net
income. A write off of regulatory assets may also reduce future cash flows since
there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - Revenues are recognized
on the accrual or settlement basis for normal retail and wholesale electricity
supply sales and electricity transmission and distribution delivery services.
The revenues are recognized in our income statement when the energy is delivered
to the customer and include unbilled as well as billed amounts. In general,
expenses are recorded when purchased electricity is received and when expenses
are incurred.
Domestic Gas Pipeline and Storage Activities - Revenues are recognized from
domestic gas pipeline and storage services when gas is delivered to contractual
meter points or when services are provided. Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts, excluding
wellhead purchases of natural gas, swaps and options for the domestic pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contacts
to fair value during the period are recognized currently in the results of
operations, appropriately discounted and net of applicable credit and liquidity
reserves.
Energy Marketing and Trading Transactions -
In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale
electricity, natural gas and other commodity marketing and trading transactions
(trading activities). Trading activities involve the purchase and sale of energy
under forward contracts at fixed and variable prices and the trading of
financial energy contracts which includes exchange futures and options and
over-the-counter options and swaps. We use the mark-to-market method of
accounting for trading activities as required by EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains
and losses from settlements of forward trading contracts are recorded net in
revenues. For energy contracts not yet settled, whether physical or financial,
changes in fair value are recorded net in revenues as unrealized gains and
losses from mark-to-market valuations. When positions are settled and gains and
losses are realized, the previously recorded unrealized gains and losses from
mark-to-market valuations are reversed. In October 2002, management announced
plans to focus on wholesale markets around owned assets.
All of the registrant subsidiaries except AEGCo participate in AEP's wholesale
marketing and trading of electricity. For I&M, KPCo, PSO and a portion of TNC
and SWEPCo, when the contract settles the total gain or loss is realized in
cash. Where this amount is recorded on the income statement depends on whether
the contract's delivery points are within or outside of AEP's traditional
marketing area. For contracts with delivery points in AEP's traditional
marketing area, the total gain or loss realized in cash for sales and the cost
of purchased energy are included in revenues on a net basis. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts in AEP's traditional marketing area are deferred as regulatory
liabilities (gains) or regulatory assets (losses). For contracts with delivery
points outside of AEP's traditional marketing area only the difference between
the accumulated unrealized net gains or losses recorded in prior periods and the
cash proceeds is recognized in the income statement as nonoperating income.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities as appropriate.
For APCo, CSPCo and OPCo, depending on whether the delivery point for the
electricity is in AEP's traditional marketing area or not determines where the
contract is reported in the income statement. Physical forward trading sale and
purchase contracts with delivery points in AEP's traditional marketing area are
included in revenues on a net basis. Prior to settlement, changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area are also included in revenues on a net basis. Physical forward
sale and purchase contracts for delivery outside of AEP's traditional marketing
area are included in nonoperating income when the contract settles. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts with delivery points outside of AEP's traditional marketing area are
included in nonoperating income on a net basis.
The trading of energy options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in AEP's revenues until the contracts settle. When these contracts
settle, the net proceeds are recorded in revenues and reverse the prior
cumulative unrealized net gain or loss. APCo, CSPCo, OPCo, I&M and KPCo also
have financial transactions, but record the unrealized gains and losses, as well
as the net proceeds upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on exchange
prices and broker quotes. Open long-term trading contracts are marked-to-market
based mainly on AEP- developed valuation models. The models are derived from
internally assessed market prices with the exception of the NYMEX gas curve,
where we use daily settled prices. All fair value amounts are net of appropriate
valuation adjustments for items such as discounting, liquidity and credit
quality. Such valuation adjustments provide for a better approximation of fair
value. The use of these models to fair value open trading contracts has inherent
risks relating to the underlying assumptions employed by such models.
Independent controls are in place to evaluate the reasonableness of the price
curve models. Significant adverse or favorable effects on future results of
operations and cash flows could occur if market prices, at the time of
settlement, do not correlate with AEP-developed price models.
As explained above, the effect on AEP's Consolidated Statements of Operations of
marking to market open electricity trading contracts in AEP's regulated
jurisdictions is deferred as regulatory assets (losses) or liabilities (gains)
since these transactions are included in cost of service on a settlement basis
for ratemaking purposes. Unrealized mark-to-market gains and losses from trading
activities whether deferred or recognized in revenues are part of Energy Trading
and Derivative Contracts assets or liabilities as appropriate.
Construction Projects for Outside Parties - Certain AEP entities engage in
construction projects for outside parties that are accounted for on the
percentage-of-completion method of revenue recognition. This method recognizes
revenue in proportion to costs incurred compared to total estimated costs.
Debt Instrument Hedging and Related Activities - In order to mitigate the risks
of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and
OPCo enter into contracts to manage the exposure to unfavorable changes in the
cost of debt to be issued. These anticipatory debt instruments are entered into
in order to manage the change in interest rates between the time a debt offering
is initiated and the issuance of the debt (usually a period of 60 days). Gains
or losses from these transactions are deferred and amortized over the life of
the debt issuance with the amortization included in interest charges. There were
no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17
- - "Risk Management, Financial Instruments and Derivatives" for further
discussion of the accounting for risk management transactions.
Levelization of Nuclear Refueling Outage Costs - In order to match costs with
regulated revenues, incremental operation and maintenance costs associated with
periodic refueling outages at I&M's Cook Plant are deferred and amortized over
the period beginning with the commencement of an outage and ending with the
beginning of the next outage.
Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS
71 requires the recordation of a regulatory asset to match the expensing of
maintenance costs with their recovery in cost-based regulated revenues. See
below for an explanation of costs deferred in connection with an extended outage
at I&M's Cook Plant.
Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement
agreements approved by the IURC and the MPSC to resolve all issues related to an
extended outage of the Cook Plant, I&M deferred $200 million of incremental
operation and maintenance costs during 1999. The deferred amount is being
amortized to expense on a straight-line basis over five years from January 1,
1999 to December 31, 2003. I&M amortized $40 million each year 1999 through 2002
leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the
Consolidated Balance Sheets of AEP and I&M.
Other Income and Other Expenses - Other Income includes non-operational revenue
including area business development and river transportation, equity earnings of
non-consolidated subsidiaries, gains on dispositions of property, interest and
dividends, an allowance for equity funds used during construction (explained
above) and miscellaneous income. Other Expenses includes non-operational expense
including area business development and river transportation, losses on
dispositions of property, miscellaneous amortization, donations and various
other non-operating and miscellaneous expenses.
AEP Consolidated Other Income and Deductions
December 31,
2002 2001 2000
---- ---- ----
(in millions)
OTHER INCOME:
Equity Earnings $ 104 $ 123 $ 22
Non-operational Revenue 187 123 71
Interest and Miscellaneous
Income 25 16 2
Gain on Sale of Frontera
- 73 -
Gain on Sale of Retail
Electric Provider 129 - -
----- ----- ----
Total Other Income $ 445 $ 335 $ 95
===== ===== ====
OTHER EXPENSES:
Property Taxes and
Miscellaneous Expenses $ 142 $ 68 $ 28
Non-operational Expenses
179 56 49
Fiber Optic and
Datapult Exit Costs - 49 -
Provision for Loss - Airplane
- 14 -
----- ----- ----
Total Other Expenses $ 321 $ 187 $ 77
===== ===== ====
Income Taxes - The AEP System follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability method, deferred income taxes are provided for all temporary
differences between the book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in regulated revenues (that
is, deferred taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are recorded and related
regulatory assets and liabilities are established in accordance with SFAS 71 to
match the regulated revenues and tax expense.
Investment Tax Credits - Investment tax credits have been accounted for under
the flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral basis.
Investment tax credits that have been deferred are being amortized over the life
of the regulated plant investment.
Excise Taxes - AEP and its subsidiary registrants, as an agent for a state or
local government, collect from customers certain excise taxes levied by the
state or local government upon the customer. These taxes are not recorded as
revenue or expense, but only as a pass-through billing to the customer to be
remitted to the government entity. Excise tax collections and payments related
to taxes imposed upon the customer are not presented in the income statement.
Debt and Preferred Stock - Gains and losses from the reacquisition of debt used
to finance domestic regulated electric utility plant are generally deferred and
amortized over the remaining term of the reacquired debt in accordance with
their rate-making treatment. If debt associated with the regulated business is
refinanced, the reacquisition costs attributable to the portions of the business
that are subject to cost based regulatory accounting under SFAS 71 are generally
deferred and amortized over the term of the replacement debt commensurate with
their recovery in rates. Gains and losses on the reacquisition of debt for
operations not subject to SFAS 71 are reported as a Loss on Reacquired Debt, an
extraordinary item on the Consolidated Statements of Operations of AEP and TCC.
See discussion of SFAS 145 in New Accounting Pronouncements section of this note
for new treatment effective in 2003.
Debt discount or premium and debt issuance expenses are deferred and amortized
utilizing the effective interest rate method over the term of the related debt.
The amortization expense is included in interest charges.
Where rates are regulated, redemption premiums paid to reacquire preferred stock
of the domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.
Goodwill and Intangible Assets - In June 2001, the FASB issued SFAS 141,
Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets,
affecting AEP and SWEPCo.
SFAS 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001 and established new
standards for the recognition of certain identifiable intangible assets,
separate from goodwill. We adopted the provisions of SFAS 141 effective July 1,
2001. See Note 12 for further discussion of acquisitions initiated after June
30, 2001 and Note 3 for further discussion of our components of goodwill and
intangible assets.
SFAS 142 requires that goodwill and intangible assets with finite useful lives
no longer be amortized, but instead tested for impairment at least annually.
SFAS 142 also requires that intangible assets with finite useful lives be
amortized over their respective estimated lives to the estimated residual
values. In accordance with SFAS 142, for all business combinations with an
acquisition date before July 1, 2001, we amortized goodwill and intangible
assets with indefinite lives through December 2001, and then ceased
amortization. The goodwill associated with those business combinations with an
acquisition date before July 1, 2001 was amortized on a straight-line basis
generally over 40 years except for the portion of goodwill associated with gas
trading and marketing activities which was amortized on a straight-line basis
over 10 years. In accordance with SFAS 142, for all business combinations with
an acquisition date after June 30, 2001, we have not amortized goodwill and
intangible assets with indefinite lives. Intangible assets with finite lives
continue to be amortized over their respective estimated lives ranging from 5 to
10 years. See Note 3 for total goodwill, accumulated amortization and the impact
on operations of the adoption of SFAS 142.
In early 2002, we began testing our goodwill and intangible assets with
indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3
for the results of our testing and the corresponding net transitional impairment
loss recorded as a Cumulative Effect of Accounting Change during 2002.
Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds
represent funds that regulatory commissions have allowed us to collect through
rates to fund future decommissioning and spent fuel disposal liabilities. By
rules or orders, the state jurisdictional commissions (Indiana, Michigan and
Texas) and the FERC established investment limitations and general risk
management guidelines to protect their ratepayers' funds and to allow those
funds to earn a reasonable return. In general, limitations include:
o Acceptable investments (rated investment grade or above)
o Maximum percentage invested in a specific type of investment
o Prohibition of investment in obligations of the applicable company or
its affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by
investment managers, who must comply with the guidelines and rules of the
applicable regulatory authorities. The trust assets are invested in order to
optimize the after-tax earnings of the Trust, giving consideration to liquidity,
risk, diversification, and other prudent investment objectives.
Securities held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are included in Other Assets at market value
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity Securities." Securities in the trust funds have been classified as
available-for-sale due to their long-term purpose. In accordance with SFAS 71,
unrealized gains and losses from securities in these trust funds are not
reported in equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or liabilities for
the spent nuclear fuel disposal trust funds in accordance with their treatment
in rates.
Comprehensive Income (Loss) - Comprehensive income (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).
There were no material differences between net income and comprehensive income
for AEGCo.
Components of Other Comprehensive Income (Loss) - Other comprehensive income
(loss) is included on the balance sheet in the equity section. The following
table provides the components that comprise the balance sheet amount in
Accumulated Other Comprehensive Income (Loss) for AEP.
December 31,
Components 2002 2001 2000
- ------------------------------------------------------------
(in millions)
Foreign Currency
Adjustments $ 4 $(113) $ (99)
Unrealized Losses
On Securities (2) - -
Unrealized Gain on
Hedged Derivatives (16) (3) -
Minimum Pension
Liability (595) (10) (4)
----- ----- -----
$(609) $(126) $(103)
===== ===== =====
Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as
of December 31, 2002 and 2001 is shown in the following table. Registrant
subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the
year ended December 31, 2000 was zero.
December 31,
Components 2002 2001
- ------------------------------------------------------
(in thousands)
Cash Flow Hedges:
APCo $(1,920) $ (340)
CSPCo (267) -
I&M (286) (3,835)
KPCo 322 (1,903)
OPCo (738) (196)
PSO (42) -
SWEPCo (48) -
TCC (36) -
TNC (15) -
Minimum Pension
Liability:
APCo $(70,162) $ -
CSPCo (59,090) -
I&M (40,201) -
KPCo (9,773) -
OPCo (72,148) -
PSO (54,431) -
SWEPCo (53,635) -
TCC (73,124) -
TNC (30,748) -
Segment Reporting - The AEP System has adopted SFAS No. 131, which requires
disclosure of selected financial information by business segment as viewed by
the chief operating decision-maker. See Note 16, "Business Segments" for further
discussion and details regarding segments.
Common Stock Options - At December 31, 2002, AEP has two stock-based employee
compensation plans with outstanding stock options, which are described more
fully in Note 15. AEP accounts for these plans under the recognition and
measurement principles of APB Opinion No. 25, Accounting for Stock Issued to
Employees and related Interpretations. No stock-based employee compensation
expense is reflected in AEP's earnings, as all options granted under these plans
had exercise prices equal to or above the market value of the underlying common
stock on the date of grant. The following table illustrates the effect on AEP's
net income (loss) and earnings (loss) per share as if AEP had applied the fair
value recognition provisions of FASB Statement No. 123, "Accounting for
Stock-Based Compensation", to stock-based employee compensation.
Year Ended December 31,
2002 2001 2000
---- ---- ----
(in millions
except per share data)
Net Income(Loss), as reported $ (519) $ 971 $ 267
Deduct: Total stock-based
employee compensation
expense determined
under fair value
based method for
all awards, net of
related tax effects (9) (12) (3)
------ ----- -----
Pro forma net income
(loss) $ (528) $ 959 $ 264
====== ===== =====
Earnings (Loss) per share:
Basic - as reported
$(1.57) $3.01 $0.83
====== ===== =====
Basic - pro forma $(1.59) $2.98 $0.82
====== ===== =====
Diluted - as reported
$(1.57) $3.01 $0.83
====== ===== =====
Diluted - pro forma $(1.59) $2.97 $0.82
====== ===== =====
Earnings Per Share (EPS) - AEP calculates earnings (loss) per share in
accordance with SFAS No. 128, "Earnings Per Share" (see Note 19). Basic earnings
(loss) per common share is calculated by dividing net earnings (loss) available
to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings (loss) per common share is
calculated by adjusting the weighted average outstanding common shares, assuming
conversion of all potentially dilutive stock options and awards. The effects of
stock options have not been included in the fiscal 2002 diluted loss per common
share calculation as their effect would have been anti-dilutive. Basic and
diluted EPS are the same in 2002, 2001 and 2000.
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned
subsidiaries of AEP and are not required to report EPS.
Reclassification - Beginning in the fourth quarter of 2002, AEP and its
registrant subsidiaries elected to begin netting certain assets and liabilities
related to forward physical and financial transactions. This is done in
accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to
Certain Contracts" and Emerging Issues Task Force Topic D-43, "Assurance That a
Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.
39". Transactions with common counterparties have been netted at the applicable
entity level, by commodity and type (physical or financial) where the legal
right of offset exists. For comparability purposes, prior periods presented in
this report have been netted in accordance with this policy.
Certain additional prior year financial statement items have been reclassified
to conform to current year presentation. Such reclassifications had no impact on
previously reported net income.
New Accounting Pronouncements
SFAS 142, "Goodwill and Other Intangible Assets", was effective for AEP on
January 1, 2002. The adoption of SFAS 142 required the transition testing for
impairment of all indefinite lived intangibles by the end of the first quarter
2002 and initial testing of goodwill by the end of the second quarter 2002. In
the first quarter 2002, AEP completed testing the goodwill of its domestic
operations and its indefinite lived intangible assets and there was no
impairment. In the second quarter 2002, AEP completed initial testing for
goodwill impairment of the U.K. and Australian retail electricity and supply
operations. The fair values of the U.K. and Australia retail electricity and
supply operations were estimated using a combination of market values based on
recent market transactions and cash flow projections. As a result of that
testing, AEP determined that there was a net transitional impairment loss, which
is reported as a cumulative effect of a change in accounting principle. See
Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges
and sales of impaired assets.
SFAS 142 also changed the accounting and reporting for goodwill and other
intangible assets. In accordance with SFAS 142 goodwill and indefinite lived
intangible assets acquired through acquisition after June 30, 2001 were not
amortized. Effective January 1, 2002, amortization related to goodwill and
indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142
requires that other intangible assets be separately identified and if they have
finite lives, they must be amortized over that life. See Note 3 for amortization
lives of AEP's and SWEPCo's intangible assets.
SFAS 143, "Accounting for Asset Retirement Obligations", is effective for AEP on
January 1, 2003. SFAS 143 generally applies to legal obligations associated with
the retirement of long-lived assets. A company is required to recognize an
estimated liability for any legal obligations associated with the future
retirement of its long-lived assets. The liability is measured at fair value and
is capitalized as part of the related asset's capitalized cost. The increase in
the capitalized cost is included in determining depreciation expense over the
expected useful life of the asset. The catch-up effect of adopting SFAS 143 will
be recorded as a cumulative effect of an accounting change. Additionally,
because the asset retirement obligation is recorded initially at fair value,
accretion expense (similar to interest) will be recognized each period as an
operating expense in the statement of operations.
The regulated entities have an asset retirement obligation associated with
nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects I&M
and TCC) and possibly other obligations. AEP expects to establish regulatory
assets and liabilities that will result in no cumulative effect adjustment of
adopting SFAS 143 for the regulated entities.
In addition, the regulated transmission and distribution entities have asset
retirement obligations related to the final retirement of certain transmission
and distribution lines. There are also underground storage tanks located at
various sites throughout the AEP System and PCB's are contained in certain
transformer rectifier sets at power plants. The amounts relating to these
obligations cannot be determined because the entities are not able to estimate
the final retirement dates for these facilities.
In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity
from recording an expense for estimated costs associated with the removal or
retirement of assets that result from other than legal obligations. The SEC
Staff concluded that amounts that are included in accumulated depreciation
related to estimated removal costs arising from other than legal obligations
should be written off as part of the cumulative effect of adopting SFAS 143
unless the company is regulated under SFAS 71. Companies regulated under SFAS 71
may continue to include removal costs in depreciation rates but must quantify
the removal costs included in accumulated depreciation as regulatory liabilities
in footnote disclosure. The AEP registrant subsidiaries that are regulated
entities have included estimated removal costs for non-legal retirement
obligations in book depreciation rates.
For non-regulated entities, including certain formerly regulated generation
facilities, asset retirement obligations associated with wind farms, closure
costs associated with power plants in the U.K. and possibly other items will be
incurred. Also the amount of removal costs embedded in accumulated depreciation
is expected to result in a favorable cumulative effect adjustment to net income.
However, AEP and its registrant subsidiaries have not completed their
determination of the net effect of these items on first quarter 2003 results of
operations upon the adoption of the provisions of this standard.
In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-lived Assets" which sets forth the accounting to recognize and
measure an impairment loss. This standard replaced, SFAS 121, "Accounting for
Long-lived Assets and for Long-lived Assets to be Disposed Of." AEP adopted SFAS
144 effective January 1, 2002. The adoption of SFAS 144 did not materially
affect AEP's results of operations or financial conditions. See Notes 3 and 13
for discussion of impairments recognized in 2002 by AEP and its registrant
subsidiaries, affected by SFAS 144.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS
145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt",
effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains
and losses from extinguishment of debt to be aggregated and classified as an
extraordinary item if material. In 2003, for financial reporting purposes AEP
and TCC will reclassify extraordinary losses net of tax on TCC's reacquired debt
of $2 million for 2001.
In October 2002, the Emerging Issues Task Force of the FASB reached a final
consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on
Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3). EITF 02-3
rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3,
mark-to-market accounting is precluded for energy trading contracts that are not
derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also
eliminate any basis for recognizing physical inventories at fair value other
than as provided by generally accepted accounting principles. The consensus is
effective for fiscal periods beginning after December 15, 2002, and applies to
all energy trading contracts entered into and inventory purchased through
October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are
required to be accounted for on a settlement basis and inventory is required to
be presented at the lower of cost or market. The effect of implementing this
consensus will be reported as a cumulative effect of an accounting change. Such
contracts and inventory will continue to be accounted for at fair value through
December 31, 2002. Energy contracts that qualify as derivatives will continue to
be accounted for at fair value under SFAS 133.
Effective January 1, 2003, EITF 02-3 requires that gains and losses on all
derivatives, whether settled financially or physically, be reported in the
income statement on a net basis if the derivatives are held for trading
purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy
trading contracts to be reported either gross or net in the income statement.
Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded
and reported upon settlement, sales under forward trading contracts as revenues
and purchases under forward trading contracts as purchased energy expenses.
Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such
forward trading revenues and purchases on a net basis, as permitted by EITF
98-10. The reclassification of such trading activity to a net basis of reporting
resulted in a substantial reduction in both revenues and purchased energy
expense, but did not have any impact on financial condition, results of
operations or cash flows.
Effective July 1, 2002, AEP and its registrant subsidiaries modified their
valuation procedures for estimating the fair value of energy trading contracts
at inception. Unrealized gain or loss at inception is recognized only when the
fair value of a contract is obtained from a quoted market price in an active
market or is otherwise evidenced by comparison to other observable market data.
Any fair value changes subsequent to the inception of a contract, however, are
recognized immediately based on the best market data available. AEP and its
registrant subsidiaries now also use such procedures for determining unrealized
gain or loss at inception for all derivative contracts.
In June 2002, FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes previous
accounting guidance, principally EITF No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. SFAS 146 requires that the liability for costs associated with
an exit or disposal activity be recognized when the liability is incurred. SFAS
146 also establishes that the liability should initially be measured and
recorded at fair value. The timing of recognizing future costs related to exit
or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS
146 for exit or disposal activities initiated after December 31, 2002.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45) which requires that a liability related to
issuing a guarantee be recognized, as well as additional disclosures of
guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107
and a rescission of FIN No. 34. The initial recognition and initial measurement
provisions of FIN 45 are effective on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements of FIN 45 are
effective for financial statements of interim and annual periods ending after
December 15, 2002. We do not expect that the implementation of FIN 45 will
materially affect results of operations, cash flows or financial condition. See
guarantee details discussed in Note 10.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure", which amends SFAS No. 123, "Accounting
for Stock-Based Compensation". SFAS 148 provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Under the fair value based method,
compensation cost for stock options is measured when options are issued. In
addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require
more prominent and more frequent (quarterly) disclosures in financial statements
of the effects of stock-based compensation. SFAS 148 is effective for fiscal
years ending after December 15, 2002. AEP does not currently intend to adopt the
fair value based method of accounting for stock options.
In November 2002, the FASB issued an Invitation to Comment, "Accounting for
Stock-Based Compensation: A Comparison of FASB Statement No. 123, Accounting for
Stock-Based Compensation, and Its Related Interpretations, and IASB Proposed
IFRS, Share-Based Payment." The FASB plans to make a decision in the first
quarter of 2003 whether it will begin a more comprehensive reconsideration of
the accounting for stock options. This may include revisiting the decision in
SFAS 123 allowing companies to disclose the pro forma effects of the fair value
based method rather than requiring recognition of the fair value of employee
stock options as an expense.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which changes the requirements for
consolidation of certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This new guidance is an
interpretation of Accounting Research Bulletin (ARB) No. 51, "Consolidated
Financial Statements". The initial recognition and initial measurement
provisions of FIN 46 for all enterprises with variable interests in variable
interest entities created after January 31, 2003, shall apply the provisions of
this Interpretation to those entities immediately. A public entity with variable
interests in variable interest entities created before February 1, 2003 shall
apply the provisions of this Interpretation no later than the beginning of the
first interim or annual reporting period beginning after June 15, 2003.
If it is reasonably possible that an enterprise will consolidate or disclose
information about a variable interest entity when this Interpretation becomes
effective, the enterprise shall disclose the following information in all
financial statements initially issued after January 31, 2003, regardless of the
date on which the variable interest entity was created:
a. The nature, purpose, size, and activities of the variable interest entity
b. The enterprise's maximum exposure to loss as a result of its involvement
with the variable interest entity
AEP and its subsidiaries believe it is reasonably possible that they will be
required to consolidate identified variable interest entities as a result of
this new guidance. See Notes 9, 22, 23 and 26 for additional disclosures
relating to the variable interest entities.
2. Extraordinary Items and Cumulative Effect:
Extraordinary Items - Extraordinary items were recorded for the discontinuance
of regulatory accounting under SFAS 71 for the generation portion of the
business in the Ohio, Virginia, West Virginia, Texas and Arkansas state
jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for
descriptions of the restructuring plans and related accounting effects. OPCo and
CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits during the quarter ended June 30, 2001. This loss resulted from
regulatory decisions in connection with Ohio deregulation which stranded the
recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo
and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies
appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the
Ohio companies believe failed to provide for recovery for the final year of the
GRT. In April 2002, the Ohio Supreme Court denied recovery of the final year of
the GRT.
In October 2001, TCC reacquired $101 million of pollution control bonds in
advance of their maturity. Since these pollution control bonds were used to
finance unregulated generation assets, a loss of $2 million after-tax was
recorded. AEP and its registrant subsidiaries had no extraordinary items in
2002.
The following table shows the components of the extraordinary items reported on
AEP's Consolidated Statements of Operations:
Year Ended
December 31,
-----------
2002 2001 2000
---- ---- ----
(in millions)
Extraordinary Items:
Discontinuance of Regulatory
Accounting for Generation:
Ohio Jurisdiction (Net of Tax
of $20 million in 2001 and
$35 Million in 2000)(a) $ - $(48) $(44)
Virginia and West Virginia
Jurisdictions (Inclusive of
Tax Benefit of $8 Million)(b) - - 9
Loss on Reacquired Debt
(Net of Tax of $1 Million
in 2001)(c) - (2) -
---- ---- ----
Extraordinary Items $ - $(50) $(35)
==== ==== ====
(a) Relates to AEP, OPCo and CSPCo.
(b) Relates to AEP and APCo.
(c) Relates to AEP and TCC.
Cumulative Effect of Accounting Change - SFAS 142 requires that goodwill and
intangible assets with indefinite useful lives no longer be amortized and be
tested annually for impairment. The implementation of SFAS 142 resulted in a
$350 million net transitional loss for our U.K. and Australian operations and is
reported in AEP's Consolidated Statements of Operations as a cumulative effect
of accounting change (see Note 3 for further details).
The FASB's Derivative Implementation Group (DIG) issued accounting guidance
under SFAS 133 for certain derivative fuel supply contracts with volumetric
optionality and derivative electricity capacity contracts. This guidance,
effective in the third quarter of 2001, concluded that fuel supply contracts
with volumetric optionality cannot qualify for a normal purchase or sale
exclusion from mark-to-market accounting and provided guidance for determining
when certain option-type contracts and forward contracts in electricity can
qualify for the normal purchase or sale exclusion.
For AEP, the effect of initially adopting the DIG guidance at July 1, 2001 was a
favorable earnings mark-to-market effect of $18 million, net of tax of $2
million. It was reported as a cumulative effect of an accounting change on AEP's
Consolidated Statements of Operations.
3. Goodwill and Other Intangible Assets:
As described in the Significant Accounting Policies footnote, AEP adopted the
provisions of SFAS 141 effective July 1, 2001. SFAS 141 requires that the
purchase method of accounting be used for all business combinations initiated
after June 30, 2001 and established new standards for the recognition of certain
identifiable intangible assets, separate from goodwill. Business combinations
initiated after June 30, 2001 (see Note 12 for details) are accounted for
utilizing SFAS 141.
SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized, but instead tested for impairment at least
annually. SFAS 142 required a two-step impairment test for goodwill. The first
step was to compare the carrying amount of the reporting unit's assets to the
fair value of the reporting unit. If the carrying amount exceeded the fair value
then the second step was required to be completed, which involves allocating the
fair value of the reporting unit to each asset and liability, with the excess
being implied goodwill. The impairment loss is the amount by which the recorded
goodwill exceeds the implied goodwill. AEP was required to complete a
"transitional" impairment test for goodwill as of the beginning of the fiscal
year in which the statement was adopted. This transitional impairment test
required that AEP complete step one of the goodwill impairment test within six
months from the date of initial adoption, or June 30, 2002. In the first quarter
2002, AEP completed the transitional impairment test of goodwill related to
domestic operations and indefinite lived intangible assets and concluded that
those assets were not impaired.
In the second quarter 2002, AEP completed testing for goodwill impairment on
AEP's U.K. and Australian retail electricity and supply operations. The fair
values of the U.K. and Australian retail electricity and supply operations were
estimated using a combination of market values based on recent market
transactions and cash flow projections. As a result of this testing, AEP
determined that there was a net transitional impairment loss of $350 million,
which was reported in AEP's Consolidated Statements of Operations as a
Cumulative Effect of Accounting Change.
SFAS 142 also requires that intangible assets with finite useful lives be
amortized over their respective estimated lives to the estimated residual
values. In accordance with SFAS 142, for all business combinations initiated
before July 1, 2001, AEP amortized goodwill and intangible assets with
indefinite lives through December 2001, and then ceased amortization. The
goodwill associated with those business combinations with acquisition dates
before July 1, 2001 was amortized on a straight-line basis generally over 40
years except for the portion of goodwill associated with gas trading and
marketing activities, which was amortized on a straight-line basis over 10
years. Also, in accordance with SFAS 142, for all business combinations with
acquisition dates after June 30, 2001, AEP has not amortized goodwill and
intangible assets with indefinite lives. Intangible assets with finite lives
continue to be amortized over their respective estimated lives ranging from 5 to
10 years.
New reporting requirements imposed by SFAS 142 include the disclosures shown
below.
Goodwill
The changes in AEP's the carrying amount of goodwill for the twelve months ended
December 31, 2002 by operating segment are:
Energy AEP
Wholesale Delivery Other Consolidated
--------- -------- ----- ------------
(in millions)
Balance January 1, 2002 $340 $37 $15 $392
Goodwill acquired 2 - - 2
Changes to Goodwill due to purchase price
adjustments 181 - - 181
Non-transitional impairment losses (173) - (12) (185)
Foreign currency exchange rate changes 6 - - 6
---- --- --- ----
Balance December 31, 2002 $356 $37 $ 3 $396
==== === === ====
Accumulated amortization of goodwill was approximately $22 million and $25
million at December 31, 2002 and 2001, respectively. A decrease of $3 million
related principally to the non-transitional impairment of goodwill on Gas Power
Systems (see Note 13a).
The transitional impairment loss related to SEEBOARD and CitiPower goodwill,
which is reported as a cumulative effect of an accounting change, is excluded
from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower,
including goodwill and acquired intangible assets no longer subject to
amortization, are reported as Assets of Discontinued Operations in AEP's
Consolidated Balance Sheets. See Note 12 related to the sale of SEEBOARD and
CitiPower.
Changes to goodwill due to purchase price adjustments of $181 million was
primarily due to purchase price adjustments related to AEP's acquisition of U.K.
Generation. The purchase price adjustments also include adjustments related to
the acquisition of Houston Pipe Line Company, MEMCO, Nordic Trading and AEP Coal
(see Note 12).
In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12
million for all goodwill related to the acquisition of Gas Power Systems (see
Note 13a).
In the fourth quarter of 2002, AEP prepared its annual goodwill impairment
tests. The fair values of the operations were estimated using cash flow
projections. There were no goodwill impairments as a result of the annual
goodwill impairment tests. However, in the fourth quarter, AEP recognized
goodwill impairment losses totaling $173 million related to impairment studies
performed on the U.K. Generation assets ($166 million), AEP Coal ($3 million),
and Nordic Trading ($4 million). These goodwill impairment studies were
triggered by the SFAS 144 asset impairment losses recognized on these operations
in the fourth quarter (refer to Note 13). The fair values of these operations
were estimated using cash flow projections.
The following tables show the transitional disclosures to adjust AEP's reported
net income (loss) and earnings (loss) per share to exclude amortization expense
recognized in prior periods related to goodwill and intangible assets that are
no longer being amortized.
Net Income (Loss) Year Ended December 31,
-----------------------
2002 2001 2000
---- ---- ----
(in millions)
Reported Net Income (Loss) $(519) $ 971 $267
Add back: Goodwill amortization (a) - 39 39
Add back: Amortization for intangibles with indefinite
lives under SFAS 142 (b) - 8 9
----- ------ ----
Adjusted Net Income (Loss) $(519) $1,018 $315
===== ====== ====
Twelve Months Ended
Earnings (Loss) Per Share (Basic and Dilutive) December 31,
-------------------
2002 2001 2000
---- ---- ----
Reported Earnings (Loss) per Share $(1.57) $3.01 $0.83
Add back: Goodwill amortization (c) - 0.12 0.12
Add back: Amortization for intangibles with
indefinite lives under SFAS 142 (d) - 0.02 0.03
------ ----- -----
Adjusted Earnings (Loss) per Share $(1.57) $3.15 $0.98
====== ===== =====
(a) This amount includes $34 million and $37 million in 2001 and 2000 related
to Seeboard and CitiPower amortization expense included in Discontinued
Operations on AEP's Consolidated Statements of Operations.
(b) The amounts shown for 2001 and 2000 relate to CitiPower amortization
expense included in Discontinued Operations on AEP's Consolidated
Statements of Operations.
(c) This amount includes $0.10 and $0.11 in 2001 and 2000 related to Seeboard
and CitiPower amortization expense included in Discontinued Operations on
AEP's Consolidated Statements of Operations.
(d) The amounts shown for 2001 and 2000 relate to CitiPower amortization
expense included in Discontinued Operations on AEP's Consolidated
Statements of Operations.
Acquired Intangible Assets
Acquired intangible assets subject to amortization are $37 million at December
31, 2002 and $33 million at December 31, 2001, net of accumulated amortization.
Of those amounts, $25 million and $33 million at December 31, 2002 and 2001,
relate to SWEPCo. The gross carrying amount, accumulated amortization and
amortization life by major asset class are:
December 31, 2002 December 31, 2001
Gross Gross
Amortization Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------ -------- ------------ ------- ------------
(in years) (in millions) (in millions)
Dolet Hills Advanced
Royalties (SWEPCo) 10 $35 $5 $35 $2
Less: Adjustment Due to
Purchase Price
Reallocation
(SWEPCo) 6 1 - -
Trade name and
Administration of
Contracts 7 2 - - -
Unpatented
Technology 10 10 - - -
--- -- --- --
Totals $41 $4 $35 $2
=== == === ==
Amortization of intangible assets (primarily SWEPCo) was $2 million for the
twelve months ended December 31, 2002. AEP's estimated aggregate amortization
expense is $4 million for each year 2003 through 2008. SWEPCo's estimated
aggregate amortization expense (included in AEP's estimated amount) is $3
million for each year 2003 through 2008.
AEP's acquired intangible assets no longer subject to amortization were
comprised of retail and wholesale distribution licenses for CitiPower operating
franchises. The licenses were being amortized on a straight-line basis over 20
and 40 years for the retail and wholesale licenses, respectively. In accordance
with SFAS 144, the assets of CitiPower, including acquired intangible assets no
longer subject to amortization, are reported as Assets of Discontinued
Operations on one line in AEP's Consolidated Balance Sheets. See Note 12 related
to the sale of CitiPower.
4. Merger:
On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9
million shares of AEP Common Stock were issued in exchange for all the
outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share
of AEP Common Stock for each share of CSW Common Stock.
The merger was accounted for as a pooling of interests. Accordingly, AEP's
consolidated financial statements give retroactive effect to the merger, with
all periods presented as if AEP and CSW had always been combined. Certain
reclassifications have been made to conform the historical financial statement
presentation of AEP and CSW. Effective January 2003, the legal name of CSW was
changed to AEP Utilities, Inc.
In connection with the merger, $10 million ($7 million after tax), $21 million
($14 million after tax) and $203 million ($180 million after tax) of
non-recoverable merger costs were expensed in 2002, 2001 and 2000. Such costs
included transaction and transition costs not recoverable from ratepayers. Also
included in the merger costs were non-recoverable changes in control payments.
Merger transaction and transition costs of $52 million recoverable from
ratepayers were deferred pursuant to state regulator approved settlement
agreements through December 31, 2002. The deferred merger costs are being
amortized over five to eight year recovery periods, depending on the specific
terms of the settlement agreements, with the amortization ($8 million, $8
million and $4 million for the years 2002, 2001 and 2000) included in
depreciation and amortization expense.
The following tables show the deferred merger cost and amortization expense of
the applicable subsidiary registrants:
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2002 December 31, 2002
----------------- -----------------
(in millions)
I&M $8.2 $1.7
KPCo 2.9 0.6
PSO 5.0 1.6
SWEPCo 3.9 1.1
TCC 9.1 2.6
TNC 2.7 0.8
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2001 December 31, 2001
----------------- -----------------
(in millions)
I&M $ 9.1 $1.7
KPCo 3.2 0.6
PSO 6.6 1.2
SWEPCo 5.0 1.1
TCC 11.8 2.6
TNC 3.5 0.8
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2000 December 31, 2000
----------------- -----------------
(in millions)
I&M $ 6.9 $0.7
KPCo 2.5 0.3
PSO 7.9 0.5
SWEPCo 6.1 0.5
TCC 14.4 1.3
TNC 4.2 0.4
Merger transition costs are expected to continue to be incurred for several
years after the merger and will be expensed or deferred for amortization as
appropriate. As hereinafter summarized, the state settlement agreements provide
for, among other things, a sharing of net merger savings with certain regulated
customers over periods of up to eight years through rate reductions which began
in the third quarter of 2000.
Summary of key provisions of Merger Rate Agreements:
State/Company Ratemaking Provisions
Texas - SWEPCo, TCC, TNC $221 million rate reduction over 6 years.
No base rate increases for 3 years post merger.
Indiana - I&M $67 million rate reduction over 8 years. Extension
of base rate freeze until January 1, 2005. Requires
additional annual deposits of $6 million to the
nuclear decommissioning trust fund for the
years 2001 through 2003.
Michigan - I&M Customer billing credits of approximately $14
million over 8 years. Extension of base rate freeze
until January 1, 2005.
Kentucky - KPCo Rate reductions of approximately $28 million over
8 years. No base rate increases for 3 years post
merger.
Oklahoma - PSO Rate reductions of approximately $28 million over
5 years. No base rate increase before January 1,
2003.
Arkansas - SWEPCo Rate reductions of $6 million
over 5 years.
Louisiana - SWEPCo Rate reductions to share merger savings estimated
to be $18 million over 8 years. Base rate
cap until June 2005.
If actual merger savings are significantly less than the merger savings rate
reductions required by the merger settlement agreements in the eight-year period
following consummation of the merger, future results of operations, cash flows
and possibly financial condition could be adversely affected.
See Note 9, "Commitments and Contingencies" for information on a court decision
concerning the merger.
5. Nuclear Plant Restart:
I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant
is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted
by the NRC. I&M shut down both units of the Cook Plant, in September 1997, due
to questions regarding the operability of certain safety systems that arose
during a NRC architect engineer design inspection.
Settlement agreements in the Indiana and Michigan retail jurisdictions that
address recovery of Cook Plant related outage costs were approved in 1999. The
IURC approved a settlement agreement that resolved all matters related to the
recovery of replacement energy fuel costs and all outage/restart costs and
related issues during the extended outage of the Cook Plant. The MPSC approved
a settlement agreement for two open Michigan power supply cost recovery
reconciliation cases that resolved all issues related to the Cook Plant
extended outage. The settlement agreements allowed:
o Deferral of $200 million of non-fuel nuclear operation and maintenance
(O&M) costs for amortization over five years ending December 31, 2003,
o Deferral of certain unrecovered fuel and power supply costs for
amortization over five years ending December 31, 2003,
o A freeze in base rates through December 31, 2003 and a fixed fuel
recovery charge through March 1, 2004 in the Indiana
jurisdiction,
o A freeze in base rates and fixed power supply costs recovery factors
until January 1, 2004 for the Michigan jurisdiction.
The amount of costs and deferrals charged to other operation and maintenance
expenses were as follows:
Year Ended December 31,
2002 2001 2000
---- ---- ----
Costs Incurred $- $ 1 $297
Amortization of Deferrals 40 40 40
- -- - -- -- --
Charged to O&M Expense $40 $41 $337
=== === ====
At December 31, 2002 and 2001, deferred O&M costs of $40 million and $80
million, respectively, remained in Regulatory Assets to be amortized through
2003. Also pursuant to the settlement agreements, accrued fuel-related revenues
of $38 million were amortized as a reduction of revenues in each of 2002, 2001
and 2000. At December 31, 2002 and 2001, fuel-related revenues of $37 million
and $75 million, respectively, were included in Regulatory Assets and will be
amortized through December 31, 2003 for both jurisdictions.
The amortization of O&M costs and fuel-related revenues deferred under Indiana
and Michigan retail jurisdictional settlement agreements will adversely affect
results of operations through December 31, 2003 when the amortization period
ends. The annual amortization of O&M costs and fuel-related revenue deferrals is
approximately $78 million.
6. Rate Matters:
Texas Fuel - Affecting AEP, SWEPCo, TCC and TNC
Prior to the start of retail competition in ERCOT on January 1, 2002, fuel
recovery for Texas utilities was a multi-step procedure. When fuel costs
changed, utilities filed with the PUCT for authority to adjust fuel factors. If
a utility's prior fuel factors resulted in material over-recovery or
under-recovery of fuel costs, the utility would also request a refund or
surcharge factor to refund or collect those amounts. While fuel factors were
intended to recover fuel costs, final settlement of these amounts was subject to
reconciliation and approval by the PUCT.
Fuel reconciliation proceedings determine whether fuel costs incurred during the
reconciliation period were reasonable and necessary. All fuel costs incurred
since the prior reconciliation date are subject to PUCT review and approval. If
material amounts are determined to be unreasonable and ordered to be refunded to
customers, results of operations and cash flows would be negatively impacted.
According to Texas Restructuring Legislation, fuel cost in the Texas
jurisdiction after 2001 is no longer subject to PUCT review and reconciliation.
During 2002, TCC and TNC filed final fuel reconciliations with the PUCT to
reconcile their fuel costs through the period ending December 31, 2001. The
ultimate recovery of deferred fuel balances at December 31, 2001 will be decided
as part of their 2004 true-up proceedings. See discussion of TCC and TNC fuel
reconciliations below.
In October 2001, the PUCT delayed the start of customer choice in the SPP area
of Texas. All of SWEPCo's Texas service territory and a small portion of TNC's
service territory are in SPP. SWEPCo's existing Texas fuel cost recovery
procedures will continue until competition begins. SWEPCo will continue to set
fuel factors and determine final fuel costs in fuel reconciliation proceedings
during the SPP delay period. The PUCT has ruled that TNC fuel factors in the SPP
area will be based upon the price-to-beat fuel factors offered by the retail
electric provider in the ERCOT portion of TNC's service territory. TNC
transferred its SPP customers to Mutual Energy SWEPCo effective December 1,
2002. TNC filed in 2002 with the PUCT to determine the most appropriate method
to reconcile fuel costs in TNC's SPP area and a decision is expected by mid
2003.
Under Texas restructuring, customer choice to select a retail electric provider
began January 1, 2002. Sales to customers using 1 MW or less will be at fixed
base rates during a transition period from 2002 through 2006. As discussed in
Note 12 "Acquisitions, Dispositions and Discontinued Operations", AEP sold its
Texas retail electric providers (REP) and their retail customers in December
2002.
The former AEP subsidiaries serving as REPs for the ERCOT area filed with the
PUCT in May 2002 to increase the fuel portion of their price-to-beat rate in
compliance with the Texas Restructuring Legislation and the PUCT's rules. The
Texas legislation provides for the adjustment of the fuel portion of the rate up
to twice annually to reflect significant changes in the market price of natural
gas and purchased energy used to serve retail customers using NYMEX natural gas
prices. On July 15, 2002, the PUCT required further hearings to reconsider the
validity of their existing rules for fuel factor adjustments. On July 24, 2002,
the Texas REPs filed a petition with the District Court seeking an injunction
commanding the PUCT to proceed to a final order based on the existing rules and
prohibiting the PUCT from conducting a remand proceeding. The District Court
issued an order on August 9, 2002 requiring the PUCT to comply with the existing
rules. On August 26, 2002, the PUCT issued an order approving a 22% increase to
the fuel portion of the price-to-beat rates effective immediately for both REPs.
The PUCT order approving the 22% increase has been appealed by parties opposing
the price-to-beat adjustment. With the sale of the REPs to Centrica in December
2002, Centrica is responsible for these appeals. Any adverse ruling from the
appeal could impact TCC and TNC by requiring refunds for the time period AEP
served the retail customers prior to the sale to Centrica (January 2002 to
December 2002).
TCC Fuel Reconciliation - Affecting AEP and TCC
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer
its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 1998 through December 2001 will be the
final fuel reconciliation. At December 31, 2001, the over-recovery balance for
TCC was $63.5 million including interest. During the reconciliation period, TCC
incurred $1.6 billion of eligible fuel and fuel-related expenses.
Recommendations from intervening parties are expected in April 2003 with
hearings scheduled in May 2003. A final order is expected in late 2003. An
adverse ruling from the PUCT could have a material impact on future results of
operations, cash flows and financial condition. Additional information regarding
the 2004 true-up proceeding for TCC can be found in Note 8 "Customer Choice and
Industry Restructuring".
TNC Fuel Reconciliation - Affecting AEP and TNC
In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any
unrecovered portion applicable to retail sales within its ERCOT service area for
inclusion in the 2004 true-up proceeding. This reconciliation for the period of
July 2000 through December 2001 will be the final fuel reconciliation for TNC's
ERCOT service territory. At December 31, 2001, the under-recovery balance
associated with TNC's ERCOT service area was $27.5 million including interest.
During the reconciliation period, TNC incurred $293.7 million of eligible fuel
costs serving both ERCOT and SPP retail customers. TNC also requested authority
to surcharge its SPP customers. TNC's SPP customers will continue to be subject
to fuel reconciliations until competition begins in SPP. The under-recovery
balance at December 31, 2001 for TNC's service within SPP was $0.7 million
including interest.
In October 2002, the filing was split into two phases for hearing purposes. The
first phase examined all components of the filing except for AEP trading
activities and the associated margins that flow back to customers as an offset
to fuel costs consistent with the PUCT - approved Texas merger settlement.
Intervenors filed testimony in the first phase recommending that up to $25
million of TNC's requested retail eligible fuel recovery be disallowed and
hearings were held on October 23, 2002. TNC disputed the recommendations. On
October 21, 2002, the PUCT Staff and Office of Public Utility Counsel (OPC)
filed a joint Motion for Summary Decision related to the second phase issue and
requested that approximately $18.5 million of TNC's retail eligible fuel
recovery be disallowed without a hearing. On November 8, 2002, the
administrative law judges (ALJs) in the case denied the motion. The intervenors
filed testimony on October 29, 2002 in the second phase recommending that up to
$34 million of TNC's requested retail eligible fuel recovery be disallowed. The
intervenors recommended disallowance includes the amount sought in the October
21 Motion for Summary Decision. The total intervenor recommended retail
disallowance is approximately $59 million. Hearings for the second phase were
held on November 13-14, 2002. On February 3, 2003, TNC filed a motion to reopen
the evidentiary record and include a decrease to retail eligible fuel costs of
$1.3 million, including interest, to reflect final resettlement revenues and
expenses from ERCOT for the period August through December 2001 (see discussion
in Fuel and Purchased Power below). The PUCT is expected to issue a final order
in this case by mid 2003. An adverse ruling from the PUCT could have a material
impact on future results of operations, cash flows and financial condition.
ERCOT Over-scheduling - Affecting AEP, TCC and TNC
ERCOT began serving as a central control center for all of ERCOT at the end of
July 2001 when ERCOT became a single control area. Qualified scheduling entities
(QSE) schedule loads and resources for ERCOT market participants including power
generation companies and retail electric providers. In August 2001, ERCOT
incurred substantial costs for managing transmission in its north zone. The
costs incurred by ERCOT to manage congestion are shared by all ERCOT QSEs. In
late 2001, the PUCT initiated an investigation of the impact of scheduling of
electric loads and resources by QSEs during August 2001. The PUCT's
investigation determined that a substantial amount of the congestion charges
were the result of QSEs, including AEP's QSE, scheduling more resources than
required to meet their actual load requirements in the ERCOT north zone. AEP's
QSE over-scheduled resources due to an error in the allocation of estimated load
requirements between ERCOT congestion zones. Pursuant to the PUCT's
investigation, QSEs, including AEP's QSE, agreed to a settlement that provides
for the refund of payments received for adjusting resource schedules for
congestion. The settlement was approved by the PUCT in November 2002. The
settlement recognizes that the scheduling errors were associated with the start
up of the ERCOT competitive market. AEP's QSE paid $3.2 million to ERCOT and
received $1.7 million from ERCOT in congestion refunds for a net payment of $1.5
million. Payments were assigned to TNC and the refunds were allocated to TCC and
TNC. TNC incurred a net cost of $2.8 million and TCC received a refund of $1.3
million. The TNC payment and TCC refund have been reflected in the final fuel
reconciliation filings for each company. However, intervening parties have
objected to the inclusion of the TNC payment in its final fuel reconciliation.
Recommendations from intervening parties in the TCC proceeding are not expected
until April 2003. An adverse ruling from the PUCT would impact future results of
operations, cash flows and financial condition.
Texas Transmission Rates - Affecting AEP, TCC and TNC
On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing
mechanism created by the PUCT in 1996 and used for the period January 1, 1997
through August 31, 1999 was invalid. The court upheld an appeal filed by
unaffiliated Texas utilities that the PUCT exceeded its statutory authority to
set such rates during that period. TCC and TNC were not parties to the case.
However, the companies' transmission sales and purchases were priced using the
invalid rates. It is unclear what action the PUCT will take to respond to the
court's ruling. If the PUCT changes rates retroactively, the result could have a
material unfavorable impact on results of operations and cash flows for TCC and
TNC.
FERC Wholesale Fuel Complaints - Affecting AEP and TNC
In May 2000, certain TNC wholesale customers filed a complaint with FERC
alleging that TNC had overcharged them through the fuel adjustment clause for
certain purchased power costs related to 1999 unplanned outages at TNC's
Oklaunion generation station. In November 2001, certain TNC wholesale customers
filed an additional complaint at FERC asserting that since 1997 TNC had billed
wholesale customers for not only the 1999 Oklaunion outage costs, but also
certain additional costs that are not permissible under the fuel adjustment
clause.
In December 2001, FERC issued an order requiring TNC to refund, with interest,
amounts associated with the May 2000 complaint that were previously billed to
wholesale customers. The effects of this order were recorded in 2001. In
response to the November 2001 complaint, negotiations to settle the complaint
and update the contracts are continuing. In March 2002, TNC recorded a provision
for refund of $2.2 million before income taxes. The actual refund and final
resolution of this matter could differ materially from this estimate and may
have a negative impact on future results of operations, cash flows and financial
condition.
FERC Transmission Rates - Affecting AEP, PSO, SWEPCo, TCC and TNC
In November 2001, FERC issued an order resulting from a remand by an appeals
court of a tariff compliance filing order issued in 1998 that had been appealed
by certain customers. The order required PSO, SWEPCo, TCC and TNC to submit
revised open access transmission tariffs and calculate and issue refunds for
overcharges from January 1, 1997. In July 2002, FERC approved a revised open
access transmission tariff and refunds of $1.3 million were issued to
unaffiliated entities.
Under FERC rules, the new tariffs resulted in a reallocation of previously
received transmission revenues among affiliates resulting in the following
income statement impact:
Increase (Decrease) Revenues
----------------------------
2001 2002 Total
(in millions)
PSO $ 2.8 $ 2.5 $ 5.3
SWEPCo 3.2 2.8 6.0
TCC (6.0) (2.8) (8.8)
TNC (2.6) (1.2) (3.8)
----- ----- -----
AEP Total $(2.6) $ 1.3 $(1.3)
===== ===== =====
Fuel and Purchased Power - Affecting AEP, PSO, SWEPCo, TCC and TNC
PSO has Under-Recovered Fuel Costs of $75.7 million at December 31, 2002,
representing fuel and purchased power costs recorded but not yet collected from
retail customers in Oklahoma. The first significant item causing the
under-recovery is approximately $44 million in reallocation of purchased power
costs for periods prior to January 1, 2002, as described below. The other
significant item impacting the under-recovered fuel costs are natural gas price
increases that were not expected when PSO set its quarterly factors during 2002.
The Corporation Commission of the State of Oklahoma (OCC) is currently reviewing
the reasons for the large under-recovered balance.
The AEP West electric operating companies' power is dispatched real-time on an
economic basis and is later allocated among the AEP West electric operating
companies using the Interchange Cost Reconstruction (ICR) system based on
dispatch information from internal and external sources. ICR is designed to
allocate the cost of power under the terms and conditions of the AEP West
Operating Agreement. During 2002, two ICR adjustments were made. The adjustments
were related to a 2002 true-up and a reallocation of years prior to 2002.
During the third quarter of 2002, AEP reallocated purchased power costs among
the four AEP West electric operating companies for the periods prior to January
1, 2002 (the ICR Adjustments). The effects of the reallocation on pre-tax income
were insignificant to PSO and TCC and increased pre-tax income at SWEPCo and TNC
by $2.4 million and $1.9 million, respectively.
The formation of the ERCOT single control zone increased the need for data
estimation and true-up which has resulted in extended true-up periods associated
with allocations being performed on estimated data. ERCOT can make adjustments
to companies' settlements for up to six months. A true-up process for 2002 was
completed and recorded in the fourth quarter of 2002 resulting in insignificant
changes in PSO's and SWEPCo's pre-tax income. TCC's pre-tax income was reduced
by $3.7 million and TNC's pre-tax income was increased by $4.8 million. As ERCOT
notifies TCC and TNC of further adjustments, they will be recorded.
PSO implemented new fuel rates in December 2002 following the OCC's review and
approval. The new fuel factors were designed to recover estimated fuel costs for
the next three months and to begin recovery of the under-recovered amount.
Recovery of the under-recovered amount is expected to occur over several months
and is subject to OCC review and approval.
For SWEPCo, the true-up process described above and the ICR Adjustments resulted
in a net increase in fuel costs recoverable from customers of $8 million
included in Regulatory Assets on AEP's and SWEPCo's Consolidated Balance Sheets.
The amount is recoverable from customers pursuant to the applicable fuel
recovery mechanisms and review of the state regulatory commissions in Arkansas,
Louisiana and Texas.
To the extent the OCC and/or the AEP West Commissions regulating SWEPCo do not
permit recovery of the revised fuel and purchased power costs, there could be an
adverse effect on results of operations and cash flows.
PSO Rate Review - Affecting AEP and PSO
In February 2003, the Director of the OCC filed an application requiring PSO to
file all documents necessary for a general rate review before August 1, 2003.
Management is unable to predict the result of this review as the documents and
data have not been assembled.
Louisiana Compliance Filing - Affecting AEP and SWEPCo
On October 15, 2002, SWEPCo filed with the Louisiana Public Service Commission
(LPSC) detailed financial information typically utilized in a revenue
requirement filing, including a jurisdictional cost of service. This filing was
required by the LPSC as a result of their order approving the merger between AEP
and CSW. The LPSC's merger order also provides that SWEPCo's base rates are
capped at the present level through mid 2005. The filing indicates that SWEPCo's
current rates should not be reduced. If the LPSC disagrees with our conclusion,
they could order SWEPCo to file all documents for a full cost of service revenue
requirement review in order to determine whether SWEPCo's capped rates should be
reduced which would adversely impact results of operations and cash flows.
FERC Long-term Contracts - Affecting AEP and AEP East and AEP West companies
In September 2002, the FERC voted to hold hearings to consider requests from
certain wholesale customers located in Nevada and Washington to break long-term
contracts which they allege are "high-priced". At issue are long-term contracts
entered during the California energy price spike in 2000 and 2001. The
complaints allege that AEP sold power at unjust and unreasonable prices. The
FERC delayed hearings to allow the parties to hold settlement discussions. In
January 2003, the FERC settlement judge assigned to the case indicated that the
parties' settlement efforts were not progressing and he recommended that the
complaint be placed back on the schedule for a hearing. In February 2003, AEP
and one of our customers agreed to terminate their contract with the customer
withdrawing its FERC complaint.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of
AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities.
In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery.
In late 2001, the utilities filed complaints that the prices for power supplied
under those contracts should be lowered because the market for power was
allegedly dysfunctional at the time such contracts were entered. The ALJ
rejected the utilities' complaint, held that the markets for future delivery
were not dysfunctional, and that the utilities had failed to demonstrate that
the public interest required that changes be made to the contracts. The ALJ's
order is preliminary and is subject to review by the FERC. The FERC will likely
rule on the ALJ's order in 2003. Management is unable to predict the outcome of
these proceedings or their impact on results of operations.
Environmental Surcharge Filing - Affecting AEP and KPCo
In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff to recover the cost of emissions control equipment being
installed at Big Sandy Plant. See NOx Reductions in Note 9 "Commitments and
Contingencies".
The surcharge request, as filed, would increase annual revenues by approximately
$21 million and must be approved by the KPSC before its inclusion in customers'
bills. If the KPSC does not approve an increase in the environmental surcharge,
results of operations and cash flows would be negatively impacted.
7. Effects of Regulation:
In accordance with SFAS 71 the consolidated financial statements include
regulatory assets (deferred expenses) and regulatory liabilities (deferred
revenues) recorded in accordance with regulatory actions in order to match
expenses and revenues from cost-based rates in the same accounting period.
Regulatory assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to reduce future
cost recoveries. Among other things, application of SFAS 71 requires that the
AEP System's regulated rates be cost-based and the recovery of regulatory assets
be probable. Management has reviewed all the evidence currently available and
concluded that the requirements to apply SFAS 71 continue to be met for all
electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and
Tennessee.
When the generation portion of the business in Arkansas, Ohio, Texas, Virginia
and West Virginia no longer met the requirements to apply SFAS 71, net
regulatory assets were written off for that portion of the business unless they
were determined to be recoverable as a stranded cost through regulated
distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In
the Ohio and West Virginia jurisdictions generation-related regulatory assets
that are recoverable through transition rates have been transferred to the
distribution portion of the business and are being amortized as they are
recovered through charges to regulated distribution customers. These assets are
classified as "transition regulatory assets". As discussed in Note 8, "Customer
Choice and Industry Restructuring" the Virginia SCC ordered the
generation-related regulatory assets in the Virginia jurisdiction to remain with
the generation portion of the business. Generation-related regulatory assets in
the Virginia jurisdiction are being amortized concurrent with their recovery
through capped rates. These assets are also classified as "transition regulatory
assets." The Texas jurisdiction generation-related regulatory assets that are
eligible for recovery through securitization have been classified as "regulatory
assets designated for or subject to securitization." See Note 8 "Customer Choice
and Industry Restructuring" for further details.
AEP's recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
-----------
2002 2001
---- ----
(in millions)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 791 $ 814
Transition Regulatory Assets 743 847
Regulatory Assets
Designated for or Subject to
Securitization 336 959
Texas Wholesale Clawback (a) 262 -
Deferred Fuel Costs 143 139
Unamortized Loss on
Reacquired Debt 83 99
Cook Plant Restart Costs 40 80
DOE Decontamination and
Decommissioning
Assessment 26 31
Other 264 193
------ ------
Total Regulatory Assets $2,688 $3,162
====== ======
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 455 $ 491
Texas Retail Clawback (a) 66 -
Other 419 393
------ -----
Total Regulatory Liabilities $ 940 $ 884
====== =====
(a) See "Texas Restructuring" section of Note 8.
The recognized regulatory assets and liabilities for the registrant subsidiaries
are of two types: those earning a return and those not earning a return. Items
not earning a return have their recovery period end date indicated. Regulatory
assets and liabilities are comprised of the following items:
AEGCo APCo
------------------------------ ------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From
Customers For Future
Income Taxes $209,884 $189,794 Note 1
Transition - Regulatory
Assets Virginia 39,670 46,981 Jun. 2007
Transition - Regulatory
Assets West Virginia 119,038 127,998 Jun. 2011
Deferred Fuel Costs 5,367 11,732
Unamortized Loss on
Reacquired Debt $ 4,970 $ 5,207 Note 2 9,147 10,421 Note 2
Deferred Storm Damage - 6
Other 12,447 10,451 Note 3
------- ------- -------- --------
Total Regulatory Assets $ 4,970 $ 5,207 $395,553 $397,383
======= ======= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $52,943 $56,304 Note 4 $ 33,691 $ 38,328 Note 4
WV Rate Stabilization 75,601 75,601 Note 5
Amounts Due To Customers
For Future Income Taxes 16,670 22,725 Note 1
Other 72 112 Note 3
------- ------- -------- --------
Total Regulatory Liabilities $69,613 $79,029 $109,364 $114,041
======= ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed
recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Amortization will be determined by the WVPSC to offset market prices.
CSPCo I&M
------------------------------- -------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 26,290 $ 28,361 Note 1 $163,928 $171,605 Note 1
Transition - Regulatory
Assets 204,961 223,830 Dec. 2008
Deferred Fuel Costs 37,501 75,002 Dec. 2003
Unamortized Loss on
Reacquired Debt 5,978 7,010 Note 2 14,994 16,255 Note 2
Cook Plant Restart Costs 40,000 80,000 Dec. 2003
Incremental Nuclear Refueling
Outage Expenses (Net) 29,572 2,995 Note 5
DOE Decontamination and
Decommissioning Assessment 23,375 27,784 Dec. 2008
Other 20,453 3,066 Note 3 38,842 35,286 Note 3
-------- -------- -------- --------
Total Regulatory Assets $257,682 $262,267 $348,212 $408,927
======== ======== ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 33,907 $ 37,176 Note 4 $ 97,709 $105,449 Note 4
Other - 31 Note 3 65,983 52,479 Note 3
-------- -------- -------- --------
Total Regulatory Liabilities $ 33,907 $ 37,207 $163,692 $157,928
======== ======== ======== ========
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Amortized over the period beginning with the commencement of an outage and
ending with the beginning of the next outage.
KPCo OPCo
------------------------------ ----------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 87,261 $83,027 Note 1 $165,106 $186,740 Note 1
Transition - Regulatory
Assets 375,409 442,707 Dec. 2007
Deferred Fuel Costs - 1,542
Unamortized Loss on
Reacquired Debt 152 51 Note 2 4,899 5,502 Note 2
Other 14,563 13,072 Note 3 23,227 9,676 Note 3
-------- ------- -------- --------
Total Regulatory Assets $101,976 $97,692 $568,641 $644,625
======== ======= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 9,165 $10,405 Note 4 $ 18,748 $ 21,925 Note 4
Other 12,152 6,551 Note 3 1,237 1,237 Note 3
-------- ------- -------- --------
Total Regulatory Liabilities $ 21,317 $16,956 $ 19,985 $ 23,162
======== ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions.
PSO SWEPCo
----------------------------- ------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From
Customers For Future
Income Taxes $ 19,855 $ 16,532 Note 1
Deferred Fuel Costs $ 76,470 $ 756 Note 1 2,865 8,839 Note 1
Unamortized Loss on
Reacquired Debt 11,138 12,381 Note 2 17,031 20,045 Note 2
Other 15,012 22,683 Note 3 12,347 15,731 Note 3
-------- ------- -------- --------
Total Regulatory Assets $102,620 $35,820 $ 52,098 $ 61,147
======== ======= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $ 32,201 $33,992 Note 4 $ 44,190 $ 48,714 Note 4
Ammounts Due To Customers
For Future Income Taxes 27,893 26,085 Note 1
Deferred Fuel Costs - 9,476 Note 1 17,226 5,487 Note 1
Other 4,391 22,444 Note 3 7,094 10,889 Note 3
-------- ------- -------- --------
Total Regulatory Liabilities $ 64,485 $91,997 $ 68,510 $ 65,090
======== ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed
recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions.
TCC TNC
---------------------------- -------------------------------
Recovery/ Recovery/
Refund Refund
2002 2001 Period 2002 2001 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $162,247 $ 200,496 Note 1
Regulatory Assets -
Designated For or Subject
To Securitization 336,444 959,294 Note 5
Deferred Fuel Costs $26,680 $ 40,389 Note 5
Texas Wholesale Clawback 262,000 - Note 5
Unamortized Loss on
Reacquired Debt 8,661 11,186 Note 2 3,283 8,272 Note 2
Deferred Debt - Restructuring 13,324 - Note 2 10,134 - Note 2
DOE Decontamination and
Decommissioning Assessment 3,170 3,170 Dec. 2004
Other 9,150 11,960 Note 3 5,000 5,461 Note 3
-------- ---------- ------- --------
Total Regulatory Assets $794,996 $1,186,106 $45,097 $ 54,122
======== ========== ======= ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $117,686 $ 122,892 Note 4 $21,510 $ 22,781 Note 4
Deferred Fuel Costs 69,026 52,572 Note 5
Texas Retail Clawback 51,926 - Note 5 14,328 - Note 5
Over - Recovery of
Transition Changes 20,870 - Jan. 2016
Purchased Power Conservation 9,560 - Note 1
Excess Earnings 46,111 62,852 Note 5 17,419 17,300 Note 4
Ammounts Due To Customers
For Future Income Taxes 12,280 13,591 Note 1
Other 6 6 Note 3 7,285 5,775 Note 3
-------- ---------- ------- --------
Total Regulatory Liabilities $315,185 $ 238,322 $72,822 $ 59,447
======== ========== ======= ========
Note 1: This amount fluctuates from month to month or year to year and has no
fixed recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Includable in TCC's and TNC's PUCT 2004 true-up proceedings. See "Texas
Restructuring" section of Note 8.
8. Customer Choice and Industry
Restructuring:
Customer choice allowing retail customers to select alternative generation
suppliers began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan,
Virginia and in the ERCOT area of Texas. Customer choice in the SPP area of
Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT.
AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.
Implementation of legislation enacted in Arkansas, Oklahoma and West Virginia to
allow retail customers to choose their electricity supplier has been delayed or
repealed. In 2001, Oklahoma delayed implementation of customer choice
indefinitely. In February 2003, the Arkansas General Assembly passed legislation
that repealed customer choice legislation, which is currently awaiting signature
by the Govenor of Arkansas. Before West Virginia's choice plan can be effective,
tax legislation must be passed to continue consistent funding for state and
local governments. No further legislation has been introduced related to
restructuring in West Virginia.
In general, state restructuring legislation provides for a transition from
cost-based rate regulated bundled electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Customer choice of electricity supplier and restructuring began on January 1,
2001, under the Ohio Act. At January 1, 2003, virtually all customers continue
to receive supply service from CSPCo and OPCo with a legislatively required
residential generation rate reduction of 5%. All customers continue to be served
by CSPCo and OPCo for transmission and distribution services.
The Ohio Act provided for a five-year transition period to move from cost-based
rates to market pricing for electric generation supply services. It granted the
PUCO broad oversight responsibility for promulgation of rules for competitive
retail electric generation service and approval of a transition plan for each
electric utility company, changed the taxation of electric companies and
addressed certain major transition issues including unbundling of rates and the
recovery of stranded costs including regulatory assets and transition costs.
In 1999 CSPCo and OPCo filed transition plans. After negotiations with
interested parties including the PUCO staff, the PUCO approved a stipulation
agreement for CSPCo's and OPCo's transition plans. The approved plans included,
among other things, recovery of generation-related regulatory assets over seven
years for OPCo and over eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and through a wires charge for
the remaining years. At December 31, 2002, the remaining amount of regulatory
assets to be amortized as recovered was $375 million for OPCo and $205 million
for CSPCo.
By provisions of the Ohio Act on May 1, 2001, electric distribution companies
became subject to an excise tax based on KWH sold to Ohio customers. The last
tax year for which Ohio electric utilities paid the excise tax based on gross
receipts was May 1, 2001 through April 30, 2002. As required by law, the gross
receipts tax is paid in advance of the tax year for which the utility exercises
its privilege to conduct business. CSPCo and OPCo treated the tax payment as a
prepaid expense and amortized it to expense during the privilege year.
The stipulation agreement also required the PUCO to consider implementation of a
gross receipts tax credit rider as the parties could not reach an agreement.
Following a hearing on the gross receipts tax issue, the PUCO ordered the gross
receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as
proposed by the companies. On April 3, 2002, the Ohio Supreme Court rejected the
companies' arguments and affirmed the PUCO's order which established the
effective date of tax credit riders in rates. This ruling had no impact on 2002
results of operations as the companies had recorded an extraordinary loss ($30
million for CSPCo and $18 million for OPCo, both amounts net of tax) in 2001.
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio
and American Municipal Power - Ohio filed a complaint with the PUCO alleging
that CSPCo and OPCo have violated the PUCO's orders regarding implementation of
their transition plan and violated other applicable law by failing to
participate in an RTO.
The complainants seek, among other relief, an order from the PUCO suspending
collection of transition charges by CSPCo and OPCo until transfer of control of
their transmission assets has occurred, pricing standard offer electric
generation effective January 1, 2006 at the market price used by the companies
in their 1999 transition plan filings to estimate transition costs and imposing
a $25,000 per company forfeiture for each day AEP fails to comply with its
commitment to transfer control of transmission assets to an RTO.
Due to the FERC's reversal of its previous approval of our RTO filings, CSPCo
and OPCo have been delayed in the implementation of their RTO participation
plans. We continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, the companies filed an
application with PUCO for approval of the transfer of functional control over
certain of their transmission facilities to PJM. Management is unable to predict
the timing of FERC's final approval of RTOs, the timing of an RTO being
operational or the outcome of these proceedings before the PUCO.
In October 2002, the PUCO initiated an investigation of the financial condition
of Ohio's regulated public utilities. The PUCO's goal is to identify measures
available to the PUCO to ensure that the regulated operations of Ohio's public
utilities are not impacted by adverse financial consequences of parent or
affiliate company unregulated operations and take appropriate corrective action,
if necessary. The utilities and other interested parties were requested to
provide comments and suggestions by November 12, 2002, with reply comments by
November 22, 2002, on the type of information necessary to accomplish the stated
goals, the means to gather the required information from the public utilities
and potential courses of action that the PUCO could take. Management is unable
to predict the outcome of the PUCO's investigation or its impact on results of
operations and business practices, if any.
Virginia Restructuring - Affecting AEP and APCo
In Virginia, choice of electricity supplier for retail customers began on
January 1, 2002 under its restructuring law. Presently, APCo continues to
service all its previous customers under capped rates. A finding by the Virginia
SCC that an effective competitive market exists would be required to end the
transition period prior to its scheduled end on June 30, 2007.
The restructuring law provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
net stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the termination
of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate
change request was made by the utility. APCo did not request new rates.
Virginia's restructuring law does not permit the Virginia SCC to change
generation rates during the transition period except for changes in fuel costs,
changes in state gross receipts taxes, or to address financial distress of the
utility.
In July 2002, APCo filed with the Virginia SCC requesting an increase in fuel
rates effective January 1, 2003. A public hearing was held on September 23, 2002
related to this filing. On November 8, 2002, a decision was issued in this
proceeding approving an annual increase of approximately $24 million.
The Virginia restructuring law also required filings to be made that outline the
functional separation of generation from transmission and distribution and a
rate unbundling plan. In January 2001 APCo filed its corporate separation plan
and rate unbundling plan with the Virginia SCC. The Virginia SCC approved
settlement agreements that resolved most issues except the assignment of
generation-related regulatory assets among functionally separated generation,
transmission and distribution organizations. The Virginia SCC determined that
generation-related regulatory assets and related amortization expense should be
assigned to APCo's generation function. Presently, capped rates are sufficient
to recover generation-related regulatory assets. Therefore, management
determined that recovery of APCo's generation-related regulatory assets remains
probable. APCo did not and will not collect a wires charge in 2002 or 2003,
respectively. The settlement agreements and related Virginia SCC order addressed
functional separation leaving decisions related to corporate separation for
later consideration.
Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC
In preparation for the start of competition in Texas, CPL, SWEPCo, and WTU, the
integrated electric utility companies operating in Texas, were required to make
PUCT filings and legal and operational changes to their business. AEP formed new
subsidiaries, Mutual Energy CPL L.P. and Mutual Energy WTU L.P., to act as
retail electric providers (REP) in Texas beginning on January 1, 2002, the
effective date of customer choice in Texas. The CPL and WTU names continued to
be used by the registrant subsidiaries which owned the generation, transmission
and distribution assets located in the ERCOT areas of Texas and WTU's entire
operations in SPP throughout most of 2002. In December 2002, WTU transferred its
SPP retail customers to Mutual Energy SWEPCO L.P. AEP sold the new subsidiaries
that serve ERCOT retail customers to Centrica in December 2002, along with the
Central Power and Light and West Texas Utilities brand names. CPL and WTU
changed their names to AEP Texas Central Company (TCC) and AEP Texas North
Company (TNC), respectively.
On January 1, 2002, customer choice of electricity supplier began in the ERCOT
area of Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. All of SWEPCo's Texas service territory and a small
portion of TNC's service territory are located in the SPP. TCC operates entirely
in the ERCOT area of Texas.
Texas restructuring legislation, among other things:
o provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for an earnings test for each of the years 1999 through 2001 which
will reduce stranded cost recoveries or if there is no stranded cost,
provides for a refund or their use to fund certain capital expenditures;
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
utility;
o provides for certain limits for ownership and control of generating
capacity by companies and;
o provides for a 2004 true-up proceeding to quantify and reconcile the amount
of stranded costs, final fuel balances, net regulatory assets, certain
environmental costs, accumulated excess earnings, excess of price-to-beat
revenues over market prices subject to certain conditions and limitations
(Retail clawback), and the difference between the price of power obtained
through the legislatively-mandated capacity auctions and the power costs
used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and
other issues.
Under the Texas Legislation, electric utilities were required to submit a plan
to structurally unbundle business activities into a retail electric provider, a
power generation company and a transmission and distribution (T&D) utility. In
2000, SWEPCo, TCC and TNC filed their business separation plans with the PUCT.
The PUCT approved the plans for TCC and TNC but determined that competition in
the SPP areas of Texas should be delayed indefinitely and abated SWEPCo's plan.
Operations for TCC and TNC have been functionally separated consistent with the
approved plans. The delivery of electricity in ERCOT continues to be the
responsibility of TCC and TNC at regulated prices.
Texas Legislation provides electric utilities an opportunity to recover
regulatory assets and stranded costs resulting from the unbundling of the T&D
utility from the generation facilities. Stranded costs are the difference
between regulatory net book value of generation assets and the market value of
the assets based on one of several methodologies authorized by the Texas
Legislation. Stranded costs can be refinanced through securitization (a
financing structure designed to provide lower financing costs than are available
through conventional financings).
In 1999, TCC filed with the PUCT to securitize $1.27 billion of its retail
generation-related regulatory assets and $47 million in other qualified
restructuring costs. The PUCT authorized the issuance of up to $797 million of
securitization bonds ($949 million of generation-related regulatory assets and
$33 million of qualified refinancing costs offset by $185 million of customer
benefits for accumulated deferred income taxes). TCC issued its securitization
bonds in February 2002. The annual cost of the bonds are recovered through a
PUCT approved transition charge in distribution rates.
TCC included regulatory assets not approved for securitization in its request
for recovery of $1.1 billion of stranded costs. The $1.1 billion request
included $800 million of STP costs included in Property, Plant and
Equipment-Electric Production on AEP's Consolidated Balance Sheets. These STP
costs had previously been identified as excess cost over market (ECOM) by the
PUCT for regulatory purposes. They were earning a lower return and being
amortized on an accelerated basis for rate-making purposes.
After hearings on the issue of stranded costs, the PUCT ruled, in October 2001,
that its current estimate of TCC's stranded costs was negative $615 million. TCC
disagreed with the ruling (see discussion of appeal ruling below). The ruling
indicated that TCC's costs were below market after securitization of regulatory
assets. The final amount of TCC's stranded costs including regulatory assets and
ECOM will be established by the PUCT in the 2004 true-up proceeding. If TCC's
total stranded costs determined in the 2004 true-up are less than the amount of
securitized regulatory assets, the PUCT can implement an offsetting credit to
transmission and distribution rates.
The Texas Legislation allows for several alternative methods to be used to value
stranded costs in the final 2004 true-up proceeding including the sale or
exchange of generation assets, stock valuation or the use of an ECOM model.
TCC decided to obtain a market value of generating assets for purposes of
determining stranded costs for the 2004 true-up proceeding and filed a plan of
divestiture with the PUCT, in December 2002, seeking approval of a sales process
for all of its generating facilities. Such sales quantify the actual stranded
costs. The amount of stranded costs under this market valuation methodology will
be the amount by which net book value of TCC's generating assets, including
regulatory assets and liabilities that were not securitized, exceeds the market
value of the generation assets as measured by the net proceeds from the sale of
the assets. It is anticipated that any such sale will result in significant
stranded costs for purposes of the 2004 true-up proceeding. The filing included
a request for the PUCT to issue a declaratory order that TCC's 25% ownership
interest in its nuclear plant, STP, can be sold to value stranded costs.
Intervenors to this proceeding, including the PUCT Staff, have made filings to
dismiss TCC's filing claiming that the PUCT does not have the authority to issue
a declaratory order. The intervenors also argued that the proper time to address
the sales process is after the plants are sold during the 2004 true-up
proceeding. Since the bidding process is not expected to be completed before mid
2004, TCC requested that the 2004 true-up proceeding be scheduled after
completion of the divestiture of the generating assets.
Texas Legislation also requires that electric utilities and their affiliated
power generation companies (PGC) sell at auction in 2002 and 2003 at least 15%
of the PGC's Texas jurisdictional installed generation capacity in order to
promote competitiveness in the wholesale market through increased availability
of generation and liquidity. Actual market power prices received in the state
mandated auctions wil replace the PUCT's earlier estimates of those market
prices used in the ECOM model to calculate the stranded cost for the 2004
true-up proceeding.
The decision to determine stranded costs using market prices, instead of using
the PUCT's ECOM model estimates, enabled TCC to record a $262 million regulatory
asset and related revenues which represents the quantifiable amount of stranded
costs for the year 2002 related to the wholesale prices. Prior to the decision
to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited
the recognition of the regulatory assets and revenues as there was no way to
quantify stranded costs. As discussed above, a defined process is required in
order to determine the amount of stranded costs related to generation facility
for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT
during December 2002 provided such a process.
When the divestiture and the 2004 true-up processing is completed, TCC will
securitize stranded costs which exceed current securitized amounts. The annual
costs of securitization will be recovered through a non-bypassable rate
surcharge by the regulated T&D utility over the life of the securitization
bonds. Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate non-bypassable
competitive transition charge to T&D utility customers.
The Texas Legislation provides for an earnings test each year 1999 through 2001
and requires PUCT approval of the annual earnings test calculation.
The PUCT issued final orders for the 1999 earnings test in February 2001 and for
the 2000 earnings test in September 2001. The 1999 excess earnings were none for
SWEPCo, $24 million for TCC and $1 million for TNC. Excess earnings for 2000
were $1 million for SWEPCo, $23 million for TCC and $17 million for TNC.
Adjustments were recorded in results of operations as the orders were received.
The PUCT issued its final order for the 2001 earnings test in December 2002. An
estimate of 2001 excess earnings of $8 million for TCC, $2 million for SWEPCo
and none for TNC had been recorded in 2001. Adjustments to reflect the PUCT
staff's estimate of excess earnings ($2 million for SWEPCo, $0.7 million for TNC
and none for TCC) were recorded prior to September 30, 2002. The PUCT's final
order regarding 2001 excess earnings required only minor adjustments to prior
estimates.
Due to TCC's and TNC's disagreement with the PUCT's final order for the 2000
excess earnings, the companies filed an appeal in district court in 2001 seeking
judicial review of the PUCT's determination of excess earnings. The district
court upheld the PUCT's order and the companies appealed that decision. A ruling
on the appeal is expected in 2003.
On January 28, 2003, the TCC and TNC filed an appeal in District Court seeking
judicial review of the PUCT order for the 2001 excess earnings.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would
be made to the amount of stranded costs authorized by the PUCT to be
securitized. Final stranded cost amounts and the treatment of excess earnings
will be determined in the 2004 true-up proceeding. To the extent that the final
2004 true-up proceeding determines that TCC should recover additional stranded
costs, the additional amount recoverable can also be securitized. The PUCT also
ruled that excess earnings for the period 1999-2001 should be refunded through
distribution rates to the extent of any over-mitigation of stranded costs
represented by negative ECOM. In 2001 the PUCT issued an order requiring TCC to
reduce distribution rates by approximately $54.8 million plus accrued interest
over a five-year period beginning January 1, 2002 in order to return estimated
excess earnings for 1999, 2000 and 2001. Since excess earnings amounts were
expensed in 1999, 2000 and 2001, the order has no additional effect on reported
net income but will reduce cash flows for the five year refund period. The
amount to be refunded is recorded as a regulatory liability.
Management believes that TCC will have stranded costs in 2004. TCC has appealed
the PUCT's refund of excess earnings to the Travis County District Court and,
depending on the outcome of that appeal (and the final outcome of the rulemaking
challenge discussed below), the PUCT may revise the treatment of excess earnings
in the final calculation of the stranded cost balance. In the same appeal, TCC
and certain unaffiliated parties also challenged various elements of the PUCT's
order determining the estimated stranded costs of TCC, with the unaffiliated
parties contending, among other things, that the entire $615 million of negative
stranded costs should be refunded presently. Prior to the Court hearing on this
issue, however, TCC agreed to give up its claims concerning errors in the
calculation of the stranded cost estimate, while the unaffiliated parties agreed
to give up claims that there should be a refund of negative stranded costs. The
Travis County District Court subsequently heard oral arguments concerning the
remaining issues in the appeal, but has not yet issued a decision. The PUCT's
stranded cost estimate that is the subject of this appeal will be superceded by
a final determination of stranded costs to be accomplished as part of the 2004
true-up proceeding.
In a separate appeal challenging the PUCT's substantive rule governing the 2004
true-up proceeding, the Texas Third Court of Appeals ruled in February 2003,
that the Texas Legislation does not contemplate the refunding of negative
stranded costs to customers. The Court of Appeals held that the PUCT was
justified in using any negative stranded cost balance determined in the 2004
true-up proceeding only as an offset to prevent an over-recovery of stranded
costs via securitization. In addition, the Court of Appeals ruled that negative
stranded costs cannot be offset against other true-up balances, including final
under-recovered fuel amounts. This ruling may be further appealed to the Supreme
Court of Texas.
Beginning January 1, 2002, fuel costs are not subject to PUCT fuel
reconciliation proceedings for TCC and TNC's ERCOT retail customers. Due to the
delay of competition for SWEPCo's SPP area of Texas, SWEPCo continues to record
and request recovery of fuel costs subject to Texas fuel proceedings. Final
deferred fuel balances related to ERCOT customers of TCC and TNC at December 31,
2001 will be included in the 2004 true-up proceeding. If the final fuel balances
or any amount incurred but not yet reconciled are not recovered, they could have
a negative impact on results of operations.
Under the Texas Legislation, retail electric providers (REPs) associated with
integrated utilities are required to offer residential and small commercial
customers (with a peak usage of less than 1000 KW) a price-to-beat rate until
January 1, 2007. In December 2001 the PUCT approved price-to-beat rates for the
AEP REPs in TCC's and TNC's ERCOT area. Customers with a peak usage of more than
1000 KW are subject to market rates. The Texas Restructuring Legislation also
provides that a REP associated with integrated utilities may request an
adjustment of its fuel portion of the price-to-beat rate up to two times
annually to reflect changes in market prices of fuel and purchased energy costs
based upon changes in NYMEX gas prices.
As part of the 2004 true-up proceedings the price-to-beat rates charged by AEP
REPs for 2002 and 2003 will be compared to the market rates for the same period.
If market rates are lower, the excess of the price-to-beat, reduced by non-
bypassable delivery charges, over the prevailing market prices must be returned
to the distribution company, subject to a per customer maximum. During 2002, AEP
provided for such potential liabilities at the maximum amount via a charge to
revenues, and recorded a regulatory liability for TCC and TNC. These amounts
were $52 million for TCC and $14 million for TNC.
West Virginia Restructuring - Affecting AEP and APCo
In 2000 the WVPSC issued an order approving an electricity restructuring plan
which the WV Legislature approved by joint resolution. The joint resolution
provides that the WVPSC cannot implement the plan until the legislature makes
tax law changes necessary to preserve the revenues of state and local
governments. Since the WV Legislature has not passed the required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.
A Joint Stipulation approved by the WVPSC in 2000 in connection with a base rate
filing, allowed for recovery of regulatory assets including any
generation-related regulatory assets through the following provisions: o Frozen
transition rates and a wires charge of 0.5 mills per KWH.
o The retention, as a regulatory liability, on the books of a net cumulative
deferred ENEC over-recovery balance of $66 million to be used to offset
the cost of deregulation when generation is deregulated in WV.
o The retention of net merger savings prior to December 31, 2004
resulting from the merger of AEP and CSW.
o A 0.5 mills per KWH wires charge for departing customers provided
for in the WV Restructuring Plan.
Management expects that the approved Joint Stipulation provides for the recovery
of existing regulatory assets and other stranded costs.
In order for customer choice to become effective in WV, the WV Legislature
needed to enact additional legislation to preserve the revenues of state and
local government. In the subsequent two legislative sessions, which usually end
in March each year, the West Virginia Legislature has not enacted the required
legislation. Due to the lack of legislative activity, the WVPSC closed two
proceedings related to electricity restructuring in the summer of 2002.
The two closed proceedings related to the respective dockets intended originally
to determine whether West Virginia should deregulate the generation business,
and to develop the WVPSC's Deregulation Plan and related rules to implement the
Plan.
Management has reviewed these two proceedings and has concluded that at this
time it is not clear that APCo meets the requirements to reapply SFAS 71.
Management will monitor developments to determine when it is appropriate to
reapply SFAS 71 to APCo's generation business.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999, Arkansas enacted legislation to restructure its electric utility
industry.
In February 2003, the Arkansas General Assembly passed legislation that repealed
customer choice legislation, which is currently awaiting signature by the
Governor of Arkansas.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas,
Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CSPCo, OPCo,
SWEPCo, TCC and TNC
The enactment of restructuring legislation and the ability to determine
transition rates, wires charges and any resultant gain or loss under
restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia
resulted in AEP and certain subsidiaries discontinuing regulatory accounting
under SFAS 71 for the generation portion of their business in those states.
Under the provisions of SFAS 71, regulatory assets and regulatory liabilities
are recorded to reflect the economic effects of regulation by matching expenses
with related regulated revenues.
The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas,
Virginia and West Virginia resulted in recognition of extraordinary gains or
losses. The discontinuance of SFAS 71 can require the write-off of regulatory
assets and liabilities related to the deregulated operations, unless their
recovery is provided through cost-based regulated rates to be collected in a
portion of operations which continues to be rate regulated. Additionally, a
company must determine if any plant assets are impaired when they discontinue
SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis
showed that there was no accounting impairment of generation assets.
As a result of deregulation of generation, the application of SFAS 71 for the
generation portion of the business in Arkansas, Ohio, Texas, Virginia and West
Virginia was discontinued. Remaining generation-related regulatory assets will
be amortized as they are recovered under terms of transition plans. Management
believes that substantially all generation-related regulatory assets and
stranded costs will be recovered under terms of the transition plans. If future
events including the 2004 true-up proceeding in Texas were to make their
recovery no longer probable, the companies would write-off the portion of such
regulatory assets and stranded costs deemed unrecoverable as a non-cash
extraordinary charge to earnings. If any write-off of regulatory assets or
stranded costs occurred, it could have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
Michigan Restructuring - Affecting AEP and I&M
Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Effective with that date the rates on I&M's Michigan customers' bills for retail
electric service were unbundled to allow customers the opportunity to evaluate
the cost of generation service for comparison with other offers. I&M's total
rates in Michigan remain unchanged and reflect cost of service. At December 31,
2002, none of I&M's customers have elected to change suppliers and no
alternative electric suppliers are registered to compete in I&M's Michigan
service territory.
Management has concluded that as of December 31, 2002 the requirements to apply
SFAS 71 continue to be met since I&M's rates for generation in Michigan continue
to be cost-based regulated.
9. Commitments and Contingencies:
Construction and Other Commitments - Affecting AEP, AEGCo, APCo, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, TCC and TNC
The AEP System has substantial construction commitments to support its
operations. Aggregate construction expenditures for 2003-2005 for consolidated
domestic and foreign operations are estimated to be $4.7 billion.
The following table shows the estimated construction expenditures of the
subsidiary registrants for 2003 - 2005:
(in millions)
AEGCo $ 70.9
APCo 1,005.7
CSPCo 418.9
I&M 601.5
KPCo 148.3
OPCo 733.4
PSO 262.3
SWEPCo 351.3
TCC 419.6
TNC 130.8
APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Certificates have been issued by both the West Virginia Public
Service Commission and the Virginia State Corporation Commission authorizing
construction and operation of the line. On December 31, 2002, the U.S. Forest
Service issued a final environmental impact statement and record of decision to
allow the use of federal lands in the Jefferson National Forest for construction
of a portion of the line. We expect additional state and federal permits to be
issued in the first half of 2003. Through December 31, 2002, we had invested
approximately $51 million in this effort. The line is estimated to cost $287
million including amounts spent to date with completion scheduled in 2006. If
the required permits are not obtained and the line is not constructed, the $51
million investment would be written off adversely affecting future results of
operations and cash flows.
Long-term contracts to acquire fuel for electric generation have been entered
into for various terms, the longest of which extends to the year 2014 for the
AEP System. The expiration date of the longest fuel contract is 2007 for APCo,
2005 for CSPCo, 2007 for I&M, 2005 for KPCo, 2012 for OPCo, 2014 for PSO, 2006
for SWEPCo and 2006 for TNC. The contracts provide for periodic price
adjustments and contain various clauses that would release the subsidiaries from
their obligations under certain force majeure conditions.
The AEP System has unit contingent contracts to supply approximately 250 MW of
capacity to unaffiliated entities through December 31, 2009. The commitment is
pursuant to a unit power agreement requiring the delivery of energy only if the
unit capacity is available.
Power Generation Facility - Affecting AEP and OPCo
AEP has entered into agreements with Katco Funding L.P. (Katco) an unrelated
unconsolidated special purpose entity. Katco has an aggregate financing
commitment of $525 million and a capital structure of which 3% is equity from
investors with no relationship to AEP or any of its subsidiaries and 97% is debt
from a syndicate of banks. Katco was formed to develop, construct, finance and
lease a power generation facility to AEP. Katco will own the power generation
facility and lease it to AEP after construction is completed. The lease will be
accounted for as an operating lease (see Note 22), therefore neither the
facility nor the related obligations are reported on AEP's balance sheet.
Payments under the operating lease are expected to commence in the first quarter
of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW),
which will use the energy produced by the facility and sell excess energy. AEP
has agreed to purchase the excess energy from DOW for resale. The use of Katco
allows AEP to limit its risk associated with the power generation facility once
the construction phase has been completed.
AEP is the construction agent for Katco, and is responsible for completing
construction by December 31, 2003, subject to unforeseen events beyond AEP's
control.
In the event the project is terminated before completion of construction, AEP
has the option to either purchase the facility for 100% of project costs or
terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation
date of the facility and continues until November 2006. The lease contains
extension options subject to the approval of Katco, and if all extension options
were exercised, the total term of the lease would be 30 years. AEP's lease
payments to Katco are sufficient for Katco to make required debt payments and
provide a return to the investors of Katco. At the end of each lease term, AEP
may renew the lease at fair market value subject to Katco's approval, purchase
the facility at its original construction cost, or sell the facility, on behalf
of Katco, to an independent third party. If the facility is sold and the
proceeds from the sale are insufficient to repay Katco, AEP may be required to
make a payment to Katco for the difference between the proceeds from the sale
and the obligations of Katco, up to 82% of the project's cost. AEP has
guaranteed a portion of the obligations of its subsidiaries to Katco during the
construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360
million, and total costs for the completed facility are expected to be
approximately $510 million. For the 30-year extended lease term, the lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently
as market interest rates increase, the payments under this operating lease will
also increase. Annual payments of approximately $12 million represent future
minimum payments during the initial term calculated using the indexed LIBOR rate
(1.38% at December 31, 2002). The Power Generation Facility collateralizes the
debt obligation of Katco. AEP's maximum exposure to loss as a result of its
involvement with Katco is 100% during the construction phase and up to 82% once
the construction is completed. Maximum loss is deemed to be remote due to the
collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter
of 2003, as a result of the issuance of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP
would record the assets, liabilities, depreciation expense, minority interest
and debt interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.
OPCo has entered into a 30-year power purchase agreement for electricity
produced by an unaffiliated entity's three-unit natural gas fired plant. The
plant was completed in 2002 and the agreement will terminate in 2032. Under the
terms of the agreement, OPCo has the option to run the plant until December 31,
2005 taking 100% of the power generated and making monthly capacity payments.
The capacity payments are fixed through December 2005 at $1.2 million per month.
For the remainder of the 30-year contract term, OPCo will pay the variable costs
to generate the electricity it purchases (up to 20% of the plant's capacity).
Nuclear Plants - Affecting AEP, I&M and TCC
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 - Affecting AEP, I&M and TCC
The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $9.5 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S., the remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $176 million per
nuclear incident payable in annual installments of $20 million. TCC could be
assessed $44 million per nuclear incident payable in annual installments of $5
million as its share of a STPNOC assessment. The number of incidents for which
payments could be required is not limited. Under an industry-wide program
insuring workers at nuclear facilities, I&M and TCC are also obligated for
assessments of up to $6.2 million and $1.6 million, respectively, for potential
claims. These obligations will remain in effect until December 31, 2007.
Insurance coverage for property damage, decommissioning and decontamination at
the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8
billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for
property damage, decommissioning and decontamination. Additional insurance
provides coverage for extra costs resulting from a prolonged accidental outage.
I&M and STPNOC utilize an industry mutual insurer for the placement of this
insurance coverage. Participation in this mutual insurer requires a contingent
financial obligation of up to $36 million for I&M and $3 million for TCC which
is assessable if the insurer's financial resources would be inadequate to pay
for losses.
The current Price-Anderson Act expired in August 2002. Its contingent financial
obligations still apply to reactors licensed by the NRC as of its expiration
date. It is anticipated that the Price-Anderson Act will be renewed with
increased third party financial protection requirements for nuclear incidents.
SNF Disposal - Affecting AEP, I&M and TCC
Federal law provides for government responsibility for permanent SNF disposal
and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per
KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being
collected from customers and remitted to the U.S. Treasury. Fees and related
interest of $224 million for fuel consumed prior to April 7, 1983 at Cook Plant
have been recorded as long-term debt. I&M has not paid the government the Cook
Plant related pre-April 1983 fees due to continued delays and uncertainties
related to the federal disposal program. At December 31, 2002, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and exceed the liability amount. TCC is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.
Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, I&M
and TCC
Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. After expiration of the licenses, Cook Plant is expected to be
decommissioned using the prompt decontamination and dismantlement (DECON)
method. The estimated cost of decommissioning and low level radioactive waste
accumulation disposal costs for Cook Plant ranges from $783 million to $1,481
million in 2000 nondiscounted dollars. The wide range is caused by variables in
assumptions including the estimated length of time SNF may need to be stored at
the plant site subsequent to ceasing operations. This, in turn, depends on
future developments in the federal government's SNF disposal program. Continued
delays in the federal fuel disposal program can result in increased
decommissioning costs. I&M is recovering estimated Cook Plant decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent decommissioning study at the time of the last rate
proceeding. The amount recovered in rates for decommissioning the Cook Plant and
deposited in the external fund was $27 million in 2002 and 2001 and $28 million
in 2000.
The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
DECON method. TCC estimates its portion of the costs of decommissioning STP to
be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering
these decommissioning costs through rates based on the service life of STP at a
rate of $8 million per year.
Decommissioning costs recovered from customers are deposited in external trusts.
In 2002 and 2001 I&M deposited in its decommissioning trust an additional $12
million each year related to special regulatory commission approved funding for
decommissioning of the Cook Plant. Trust fund earnings increase the fund assets
and the recorded liability and decrease the amount needed to be recovered from
ratepayers. Decommissioning costs including interest, unrealized gains and
losses and expenses of the trust funds are recorded in Other Operation expense
for Cook Plant. For STP, nuclear decommissioning costs are recorded in Other
Operation expense, interest income of the trusts are recorded in Nonoperating
Income and interest expense of the trust funds are included in Interest Charges.
On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are
included in Other Assets and a corresponding nuclear decommissioning liability
is included in Other Noncurrent Liabilities. On TCC's balance sheets, the
nuclear decommissioning liability of $98 million is included in Electric Utility
Plant-Accumulated Depreciation and Amortization. The decommissioning liability
for both nuclear plants combined totals $719 million and $699 million at
December 31, 2002 and 2001, respectively.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo
Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. Federal EPA and a
number of states alleged that AEP System companies and eleven unaffiliated
utilities modified certain units at coal fired generating plants in violation of
the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S.
District Court for the Southern District of Ohio. A separate lawsuit initiated
by certain special interest groups was consolidated with the Federal EPA case.
The alleged modification of the generating units occurred over a 20 year period.
Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the
District Court ruled claims for civil penalties based on activities that
occurred more than five years before the filing date of the complaints cannot be
imposed. There is no time limit on claims for injunctive relief.
Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense.
Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
unable to predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be determined by
the Court. In the event the AEP System companies do not prevail, any capital and
operating costs of additional pollution control equipment that may be required
as well as any penalties imposed would adversely affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates and market prices for electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain
plants jointly owned by CSPCo, reached a tentative agreement with the Federal
EPA and other parties to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing between the parties in an
attempt to reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned
25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly owned
facilities and its results of operations and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and
TCC
Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions
in a number of eastern states, including certain states in which the AEP
System's generating plants are located. The NOx Rule has been upheld on appeal.
The compliance date for the NOx Rule is May 31, 2004.
In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting
petitions filed by certain northeastern states under the Clean Air Act. The rule
imposed emissions reduction requirements comparable to the NOx Rule beginning
May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities,
including certain AEP operating companies, petitioned the D.C. Circuit Court to
review the Section 126 Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify the
methods it used to allocate allowances and project growth for both the NOx Rule
and the Section 126 Rule. AEP subsidiaries and other utilities requested that
the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance date. In August 2001 the D.C. Circuit Court issued an order tolling
the compliance schedule until Federal EPA responded to the Court's remand. On
April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date
for the Section 126 Rule. Federal EPA published a notice in the Federal Register
in May 2002 advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and
industrial organizations in seeking a review of Federal EPA's action in the D.C.
Circuit Court. This action is pending.
In 2000 the Texas Commission on Environmental Quality (formerly the Texas
Natural Resource Conservation Commission) adopted rules requiring significant
reductions in NOx emissions from utility sources, including SWEPCo and TCC. The
compliance date is May 2003 for TCC and May 2005 for SWEPCo.
AEP is installing a variety of emission control technologies to reduce NOx
emissions to comply with the applicable state and Federal NOx requirements. This
includes selective catalytic reduction (SCR) technolocy on certain units and
non-SCR technologies on a larger number of units. During 2001 SCR technology
commenced operations on OPCo's Gavin Plant. Installation of SCR technology on
Amos and Mountaineer plants was completed and commenced operation in May 2002.
Construction of SCR technology at certain other AEP generating units continues.
Non-SCR technologies have been installed and commenced operation on a number of
units across the AEP System and additional units will be equipped with these
technologies.
The AEP NOx compliance plan is a dynamic plan that is continually reviewed and
revised as new information becomes available on the performance of installed
technologies and the cost of planned technologies. Certain compliance steps may
or may not be necessary as a result of this new information. Consequently, the
plan has a range of possible outcomes. Our current estimates indicate that
compliance with the NOx Rule, the Texas Commission on Environmental Quality rule
and the Section 126 Rule could result in required capital expenditures in the
range of $1.3 billion to $2 billion of which $843 million has been spent through
December 31, 2002 for the AEP System. The range of cost estimate reflects the
uncertainty over the need for certain SCR projects. Estimated compliance cost
ranges and amounts spent by registrant subsidiaries at December 31, 2002, are as
follows:
Estimated Amount Spent
Compliance Costs
---------------- ------------
(in millions)
AEGCo $30 - 198 $ 1
APCo 445 234
CSPCo 93 45
I&M 42 - 210 5
KPCo 163 135
OPCo 535 - 864 387
SWEPCo 40 24
TCC 5 5
Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the estimates depending upon the
compliance alternatives selected to achieve reductions in NOx emissions. Unless
any capital and operating costs of additional pollution control equipment are
recovered from customers, they will have an adverse effect on results of
operations, cash flows and possibly financial condition.
Merger Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC
On January 18, 2002, the U.S. Court of Appeals for the District of Columbia
ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW
meets the requirements of the PUHCA and sent the case back to the SEC for
further review. Specifically, the 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 - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and
its subsidiaries in the bankruptcy proceeding filed by the Enron entities which
are pending in the U.S. Bankruptcy Court for the Southern District of New York.
At the date of Enron's bankruptcy AEP had open trading contracts and trading
accounts receivables and payables with Enron. In addition, on June 1, 2001, we
purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related
contingencies and indemnities remained unsettled at the date of Enron's
bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court
is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive rights to
use and operate the underground Bammel gas storage facility pursuant to an
agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This
exclusive right to use the referenced facility is for a term of 30 years, with a
renewal right for another 20 years and includes the use of the Bammel storage
reservoir and the related compression, treating and delivery systems. We have
engaged in preliminary discussions with Enron concerning the possible purchase
of the residual interest held by Enron in the Bammel storage facility and the
possible resolution of outstanding issues between AEP and Enron relating to our
acquisition of its interest in the Bammel storage facility. We are unable to
predict whether these discussions will lead to an agreement on these subjects.
If these discussions do not lead to an agreement, there may be a dispute with
Enron concerning our ability to continue utilization of the Bammel storage
facility under the existing agreement.
We also entered into an agreement with BAM Lease Company which grants HPL the
right to use approximately 65 billion cubic feet of cushion gas (or pad gas)
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust, which purportedly owned approximately 55 billion cubic feet of the
gas, had entered into a financing arrangement in 1997 with Enron and a group of
banks. These banks purported to have certain rights to the gas in certain events
of default. In connection with AEP's acquisition of HPL, the banks entered into
an agreement granting HPL's use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was thereafter
informed by the banks of a purported default by Enron under the terms of the
referenced financing arrangement. In July 2002 the banks filed a lawsuit against
HPL seeking a declaratory judgment that they have a valid and enforceable
security interest in this cushion gas which would permit them to cause the
withdrawal of this gas from the storage facility. In September 2002 HPL filed a
general denial and certain counterclaims against the banks. Management is unable
to predict the outcome of this lawsuit or its impact on results of operations
and cash flows.
In 2001 AEP expensed $47 million ($31 million net of tax) for our estimated loss
from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a
cumulative loss of $53 million ($34 million net of tax). The amounts for certain
subsidiary registrants were:
Amounts
Amounts Net of
Registrant Expensed Tax
-------- -----
(in millions)
APCo $5.3 $3.4
CSPCo 2.7 1.8
I&M 2.8 1.8
KPCo 1.1 0.7
OPCo 3.6 2.3
The additional 2002 expense did not materially change the cumulative expense per
registrant subsidiary. The amounts expensed were based on an analysis of
contracts where AEP and Enron entities are counterparties, the offsetting of
receivables and payables, the application of deposits from Enron entities and
management's analysis of the HPL related purchase contingencies and
indemnifications.
Enron has recently instituted proceedings against other energy trading
counter-parties challenging the practice of utilizing offsetting receivables and
payables and related collateral across various Enron entities. We believe that
we have the right to utilize similar procedures in dealing with payables,
receivables and collateral with Enron entities by offsetting approximately $110
million of trading payables owed to various Enron entities against trading
receivables due to us. We believe we have legal defenses to any challenge that
may be made to the utilization of such offsets but at this time are unable to
predict the ultimate resolution of this issue.
Shareholder Lawsuits - Affecting AEP
In the fourth quarter of 2002 lawsuits alleging securities law violations and
seeking class action certification were filed in federal District Court,
Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits,
members of the AEP Board of Directors and certain investment banking firms. The
lawsuits claim that AEP failed to disclose that alleged "round trip" trades
resulted in an overstatement of revenues, that AEP failed to disclose that AEP
traders falsely reported energy prices to trade publications that published gas
price indices and that AEP failed to disclose that it did not have in place
sufficient management controls to prevent round trip trades or false reporting
of energy prices. The plaintiffs seek recovery of an unstated amount of
compensatory damages, attorney fees and costs. The cases are presently pending a
decision by the Court on competing motions by certain plaintiffs and groups of
plaintiffs' for designation as lead plaintiff. Once the Court selects a lead
plaintiff, that lead plaintiff will file an amended complaint. AEP intends to
vigorously defend against these actions. Also in the fourth quarter of 2002, two
shareholder derivative actions were filed in state court in Columbus, Ohio
against AEP and its Board of Directors alleging a breach of fiduciary duty for
failure to establish and maintain adequate internal controls over AEP's gas
trading operations; and, a lawsuit was filed against AEP, certain AEP executives
and AEP's ERISA Plan Administrator in federal District Court for the Southern
District of New York (subsequently transferred to federal District Court in
Columbus, Ohio) alleging violations of the Employee Retirement Income Security
Act in the selection of AEP stock as a investment alternative and in the
allocation of assets to AEP stock. These cases are in the initial pleading
stage. AEP intends to vigorously defend against these actions.
California Lawsuit - Affecting AEP
In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a
lawsuit in Los Angeles County, California Superior Court against forty energy
companies including AEP and two publishing companies alleging violations of
California law through alleged fraudulent reporting of false natural gas price
and volume information with an intent to affect the market price of natural gas
and electricity. This case is in the initial pleading stage. AEP intends to
vigorously defend against this action.
Arbitration of Williams Claim - Affecting AEP
In October 2002, AEP filed its demand for arbitration with the American
Arbitration Association to initiate formal arbitration proceedings in a dispute
with the Williams Companies (Williams). The proceeding results from Williams'
repudiation of its obligations to provide physical power deliveries to AEP and
Williams' failure to provide the monetary security required for natural gas
deliveries by AEP. Consequently, both parties claimed default and terminated all
outstanding natural gas and electric power trading deals among the various
Williams and AEP affiliates. Williams claimed that AEP owes approximately $130
million in connection with the termination and liquidation of all trading deals.
AEP believes it has valid claims arising from Williams' actions and is seeking,
in part, a determination that either no amount is due or that a lesser amount is
due from AEP to Williams (which is fully reserved by AEP) and the extent of any
other damages and legal or equitable relief available. Although management is
unable to predict the outcome of this matter, it is not expected to have a
material impact on results of operations, cash flows or financial condition.
Energy Market Investigations - Affecting AEP
In February 2002, the FERC issued an order directing its Staff to conduct a
fact-finding investigation into whether any entity, including Enron, manipulated
short-term prices in electric energy or natural gas markets in the West or
otherwise exercised undue influence over wholesale prices in the West, for the
period January 1, 2000, forward. In April 2002 AEP furnished certain information
to the FERC in response to their related data request.
Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further
data requests, including requests for admissions, with respect to certain
trading strategies engaged in by Enron and, allegedly, traders of other
companies active in the wholesale electricity and ancillary services markets in
the West, particularly California, during the years 2000 and 2001. This data
request was issued to AEP as part of a group of over 100 entities designated by
the FERC as all sellers of wholesale electricity and/or ancillary services to
the California Independent System Operator and/or the California Power Exchange.
The May 8, 2002 FERC data request required senior management to conduct an
investigation into our trading activities during 2000 and 2001 and to provide an
affidavit as to whether we engaged in certain trading practices that the FERC
characterized in the data request as being potentially manipulative. Senior
management complied with the order and denied our involvement with those trading
practices.
On May 21, 2002, the FERC issued a further data request with respect to this
matter to us and over 100 other market participants requesting information for
the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back"
trading in the Western System Coordinating Council (WSCC), which involves the
sale of an electricity product to another company together with a simultaneous
purchase of the same product at the same price (collectively, "wash sales").
Similarly, on May 22, 2002, the FERC issued an additional data request with
respect to this matter to us and other market participants requesting similar
information for the same period with respect to the sale of natural gas products
in the WSCC and Texas. After reviewing our records, we responded to the FERC
that we did not participate in any "wash sale" transactions involving power or
gas in the relevant market. We further informed the FERC that certain of our
traders did engage in trades on the Intercontinental Exchange, an electronic
electricity trading platform owned by a group of electricity trading companies,
including us, on September 21, 2001, the day on which all brokerage commissions
for trades on that exchange were donated to charities for the victims of the
September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a
"wash sale" but do have certain characteristics in common with such sales. In
response to a request from the California attorney general for a copy of AEP's
responses to the FERC inquires, we provided the pertinent information.
The PUCT also issued similar data requests to AEP and other power marketers. AEP
responded to such data request by the July 2, 2002 response date. The U.S.
Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17,
2002 requesting information with respect to "wash sale" trading practices. AEP
responded to CFTC. In addition, the U.S. Department of Justice made a civil
investigation demand to AEP and other electric generating companies concerning
their investigation of the Intercontinental Exchange. AEP has completed a review
of our trading activities in the United States for the last three years
involving sequential trades with the same terms and counterparties. The revenue
from such trading is not material to our financial statements. AEP believes that
substantially all these transactions involve economic substance and risk
transference and do not constitute "wash sales".
In August 2002, AEP received an informal data request from the SEC asking us to
voluntarily provide documents related to "round trip" or "wash" trades. AEP has
provided the requested information to the SEC.
In September 2002, AEP received a subpoena from FERC requesting information
about our natural gas transactions and their potential impact on gas commodity
prices in the New York City area. AEP responded to the subpoena in October 2002.
In October 2002, AEP dismissed several employees involved in natural gas
marketing and trading after the Company determined that they provided inaccurate
price information for use in indexes compiled and published by trade
publications. AEP, subsequently, instituted measures that require all price
information for use in market indexes be verified and reported through AEP's
chief risk officer's organization. AEP has and will continue to provide to the
FERC, the SEC and the CFTC information relating to price data given to energy
industry publications.
FERC Proposed Standard Market Design - Affecting AEP System
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, one of the most sweeping rulemaking proposals in its
history. The proposed SMD rule seeks to standardize the structure and operation
of wholesale electricity markets across the country. Key elements of FERC's
proposal include standard rules and processes for all users of the electricity
transmission grid, new transmission rules and policies, and the creation of
certain markets to be operated by independent administrators of the grid in all
regions. The FERC recently indicated that it would issue a white paper on the
proposal in April 2003, in response to the numerous comments FERC received on
its proposal. The FERC is expected to issue its final rule in mid to late 2003.
Because the rule is not yet finalized, management cannot predict the effect of
the final rule on cash flows and results of operations.
FERC Proposed Security Standards - Affecting AEP System
The FERC published for comment its proposed security standards as part of the
SMD. These standards are intended to ensure all market participants have a basic
security program that effectively protects the electric grid and related market
activities. They require compliance by January 1, 2004. The impact of these
proposed standards is far-reaching and includes significant penalties for
non-compliance. These standards apply to market operations and transmission
owners. For the AEP System this includes: power generation plants, transmission
systems, distribution systems and related areas of business. FERC is considering
new proposals to modify the scope and timetable for compliance with the
standards. Unless FERC changes the scope and timing of the original proposed
standards, those standards could result in significant expenditures and
operational changes in a compressed time frame, and may adversely affect results
of operations and cash flows if such costs are not recovered from customers.
FERC Market Power Mitigation - Affecting AEP System
A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. No such
conference has been held and management is unable to predict the timing of any
further action by the FERC or its affect on future results of operations and
cash flows.
Other - AEP and its subsidiaries are involved in a number of other legal
proceedings and claims. While management is unable to predict the ultimate
outcome of these matters, it is not expected that their resolution will have a
material adverse effect on results of operations, cash flows or financial
condition.
10. Guarantees:
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to
recognize a liability related to issuing a guarantee, as well as additional
disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57,
and 107 and a rescission of FIN 34. The initial recognition and initial
measurement provisions of FIN 45 is effective on a prospective basis to
guarantees issued or modified after December 31, 2002. The disclosure
requirements of FIN 45 are effective for financial statements of interim or
annual periods ending after December 15, 2002.
There are no liabilities recorded for all of the guarantees described below in
accordance with FIN 45 as these guarantees were entered into prior to December
31, 2002. There is no collateral held in relation to these guarantees and there
is no recourse to third parties in the event these guarantees are drawn.
Certain AEP subsidiaries have entered into standby letters of credit (LOC) with
third parties. These LOCs cover gas and electricity trading contracts,
construction contracts, insurance programs, security deposits, debt service
reserves, drilling funds and credit enhancements for issued bonds. All of these
LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary
course of business. TCC issued one of the LOCs for credit enhancement of issued
bonds. The maximum future payments of all the LOCs are approximately $166
million with maturities ranging from January 2003 to December 2007. TCC's LOC
was for $40.9 million with a maturity date of November 2003. Since AEP is the
parent to all these subsidiaries, it holds all assets of the subsidiary as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.
The following AEP subsidiaries have entered into guarantees of third parties
obligations:
CSW Energy and CSW International have guaranteed 50% of the required debt
service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a
50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve
as a part of financing. In the event that Sweeny does not make the required debt
payments, CSW Energy and CSW International have a maximum future payment
exposure of approximately $3.7 million, which expires June 2020.
Additionally, CSW guaranteed 50% of the required debt service reserve for Polk
Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk
Power does not make the required debt payments, CSW has a maximum future payment
exposure of approximately $4.7 million, which expires July 2010.
In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to
assume the revolving credit agreement, capital lease obligations, and term loan
payments of the mining contractor. In the event the mining contractor defaults
under any of these agreements, SWEPCo's total future maximum payment exposure is
approximately $74 million with maturity dates ranging from April 2003 to
February 2012.
As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At December 31, 2002 the cost to reclaim the mine is estimated to
be approximately $36 million. This guarantee ends upon depletion of reserves
estimated at 2035 plus 6 years to complete reclamation.
In connection with the ability for Mutual Energy CPL L.P. (former subsidiary of
AEP sold to Centrica on December 23, 2002) to compete in the CPL territory and
to secure transition charges, AEP provided a guarantee that AEP would pay
transition charges if Mutual Energy CPL failed to meet certain obligations. At
the time of sale this guarantee (matures in February 2003) was not revoked. The
future maximum payment exposure is $12.2 million. In February 2003, the
guarantee matured and no payments under the guarantee were required.
In connection with the ERCOT transmission congestion auction, AEP has guaranteed
the obligations of Mutual Energy CPL L.P. (former subsidiary of AEP sold to
Centrica on December 23, 2002) and Mutual Energy WTU L.P. (former subsidiary of
AEP sold to Centrica on December 23, 2002). At the time of sale these guarantees
were not revoked. The total future maximum payment exposure for both companies
is approximately $0.6 million. In January 2003 these guarantees matured and no
payments under the guarantees were required.
See Note 26 "Minority Interest in Finance Subsidiary" for disclosure for the
guaranteed support of AEP for Caddis Partners, LLC.
AEP and all its registrant and non-registrant subsidiaries enter into several
types of contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease agreements,
purchase agreements and financing agreements. Generally these agreements may
include, but are not limited to, indemnifications around certain tax,
contractual and environmental matters. At this time AEP cannot estimate the
maximum potential payment for any of these indemnifications due to the
uncertainty of future events. In addition, as of December 31, 2002, there are no
liabilities required for any indemnifications.
AEP and its regulated and non-regulated subsidiaries lease certain equipment
under a master operating lease. Under the lease agreement, the lessor is
guaranteed to receive up to 87% of the unamortized balance of the equipment at
the end of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have committed to
pay the difference between the fair market value and the unamortized balance,
with the total guarantee not to exceed 87% of the unamortized balance. At
December 31, 2002, the maximum potential loss for these lease agreements was
approximately $50 million assuming the fair market value of the equipment is
zero at the end of the lease term. The maximum potential loss by registrant is
as follows:
Registrant Maximum Potential Loss
- ---------- ----------------------
(in millions)
APCo $ 0.7
CSPCo 0.8
I&M 2.0
KPCo -
OPCo 0.7
PSO 3.3
SWEPCo 3.4
TCC 6.7
TNC 2.5
Other AEP non-registrant
Subsidiaries 29.9
-----
Total $50.0
=====
11. Sustained Earnings Improvement Initiative:
In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth. Termination benefits expense relating to 1,120 terminated
employees totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. Of this amount, AEP paid $9.5 million to these terminated employees in the
fourth quarter of 2002. The termination benefits expense was classified as
Maintenance and Other Operation expense on AEP's Consolidated Statements of
Operations and as Other Operation expense on the other registrant's statements
of operations. We determined that the termination of the employees under our SEI
initiative did not constitute a curtailment under the provisions of SFAS No. 88
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits".
The following table shows the staff reductions, termination benefits expense and
the remaining termination benefits expense accrual as of December 31, 2002:
Total Total
Number Total Termination
of Expense Benefits
Terminated Recorded in Accrued at
Employees 2002 12/31/02
--------- --------- -----------
(in millions) (in millions)
AEGCo - $ 0.3 $ 0.3
APCo 93 13.1 12.2
CSPCo 19 5.0 4.5
I&M 146 15.0 13.1
KPCo 16 2.6 2.5
OPCo 33 7.5 7.1
PSO 17 3.1 3.0
SWEPCo 8 3.3 3.1
TCC 37 6.0 5.5
TNC 20 2.0 1.6
Other AEP
Subsidiaries 731 17.5 13.0
----- ----- -----
Totals 1,120 $75.4 $65.9
===== ===== =====
Approximately $48 million of severance expense associated with 701 AEP Service
Corporation employees (included in the 731 figure above) was allocated among all
AEP subsidiaries. AEGCo has no employees but receives allocated expenses.
In addition, certain buildings and corporate aircraft are being sold in an
effort to reduce ongoing operating expenses.
12. Acquisitions, Dispositions and Discontinued Operations:
Acquisitions
SFAS 141 "Business Combinations" applies to all business combinations initiated
and consummated after June 30, 2001.
2002
Acquisition of Nordic Trading
In January 2002 AEP acquired for $2.2 million and other assumed liabilities the
trading operations, including key staff, of Enron's Norway and Sweden-based
energy trading businesses (Nordic Trading). Results of operations are included
in AEP's Consolidated Statements of Operations from the date of acquisition. The
excess of cost over fair value of the net assets acquired was approximately $4.0
million which was recorded as Goodwill. Subsequently in the fourth quarter of
2002, a decision was made to exit the non-core trading business in Europe and to
close or sell Nordic Trading as discussed under the "Discontinued Operations"
section of this note.
Acquisition of USTI
In January 2002, AEP acquired 100% of the stock of United Sciences Testing, Inc.
(USTI) for $12.5 million. USTI provides equipment and services related to
automated emission monitoring of combustion gases to both AEP affiliates and
external customers. Results of operations are included in AEP's Consolidated
Statements of Operations from the date of acquisition.
2001
On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe
Line Company and Lodisco LLC for $727 million from Enron. The acquired assets
include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a
gas storage facility and certain gas marketing contracts. The purchase method of
accounting was used to record the acquisition. According to APB Opinion No. 16
"Business Combinations" AEP recorded the assets acquired and liabilities assumed
at their estimated fair values determined by independent appraisal or by
Company's management based on information currently available and on current
assumptions as to future operations. Based on a final purchase price allocation
the excess of cost over fair value of the net assets acquired was approximately
$153 million and is recorded as Goodwill. SFAS 142 "Goodwill and Other
Intangible Assets" treats goodwill as a non-amortized, non-wasting asset
effective January 1, 2002. Therefore, Goodwill was amortized for only seven
months in 2001 on a straight-line basis over 30 years. The purchase method
results in the assets, liabilities and earnings of the acquired operations being
included in AEP's consolidated financial statements from the purchase date.
AEP also purchased the following assets or acquired the following businesses
from July 1, 2001 through December 31, 2001 for an aggregate total of $1,651
million:
o SWEPCo, an AEP subsidiary, purchased the Dolet Hills mining operations
and assumed the existing mine reclamation liabilities at its jointly
owned lignite reserves in Louisiana.
o Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP
also assumed additional liabilities of approximately $58 million. The
acquisition includes property, coal reserves, mining operations and
royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West
Virginia. AEP continues to operate the mines and facilities which
employ over 800 individuals. See Note 13b "Asset Impairments and
Investment Value Losses".
o MEMCO Barge Line added 1,200 hopper barges and 30 towboats to AEP's
existing barging fleet. MEMCO's 450 employees operate the barge line.
MEMCO added major barging operations on the Mississippi and Ohio rivers
to AEP's barging operations on the Ohio and Kanawha rivers.
o U.K. Generation added 4,000 megawatts of coal-fired generation from
Fiddler's Ferry, a four-unit, 2,000-megawatt station on the River
Mersey in northwest England, approximately 200 miles from London and
Ferrybridge, a four-unit, 2,000-megawatt station on the River Aire in
northeast England, approximately 200 miles from London and related coal
stocks. See Note 13b "Asset Impairments and Investment Value Losses".
o A 20% equity interest in Caiua, a Brazilian electric operating company
which is a subsidiary of Vale. See Note 21, "Power and Distribution
Projects". AEP converted a total of $66 million on an existing loan and
accrued interest on that loan into Caiua equity. See Note 13b "Asset
Impairments and Investment Value Losses".
o Indian Mesa Wind Project consisting of 160 megawatts of wind
generation located near Fort Stockton, Texas.
o Acquired existing contracts and hired key staff from Enron's
London-based international coal trading group.
Regarding the 2002 and 2001 acquisitions, management has recorded the assets
acquired and liabilities assumed at their estimated fair values in accordance
with APB Opinion No. 16 and SFAS 141 as appropriate based on currently available
information and on current assumptions as to future operations.
Dispositions
2002
In 2002, AEP completed a number of disposals of assets determined to be
non-core:
Disposal of SEEBOARD
On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an
agreement, subject to European Union (EU) approval, to sell its consolidated
subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU
approval was received July 25, 2002 and the sale was completed on July 29, 2002.
AEP received approximately $941 million in net cash from the sale, subject to a
working capital true up, and the buyer assumed SEEBOARD debt of approximately
$1.12 billion, resulting in a net loss of $345 million at June 30, 2002. In
accordance with SFAS 144 the results of operations of SEEBOARD have been
classified as Discontinued Operations for all years presented. A net loss of $22
million was classified as Discontinued Operations in the second quarter of 2002.
The remaining $323 million of the net loss has been classified as a transitional
impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and has been
reported as a Cumulative Effect of Accounting Change retroactive to January 1,
2002. A $59 million reduction of the net loss was recognized in the second half
of 2002 to reflect changes in exchange rates to closing, settlement of working
capital true-up and selling expenses. The net total loss recognized on the
disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were
used to pay down bank facilities and short-term debt.
The assets and liabilities of SEEBOARD were aggregated on AEP's Consolidated
Balance Sheets as Assets of Discontinued Operations and Liabilities of
Discontinued Operations as of December 31, 2001. The major classes of SEEBOARD's
assets and liabilities of discontinued operations were:
December 31,
2001
-----------
(in millions)
Assets:
Current Assets $ 324
Plant,Property and Equipment, Net 1,283
Goodwill 1,129
Other Assets 96
------
Total Assets of Discontinued
Operations $2,832
Liabilities:
Current Liabilities $ 752
Long-term Debt 701
Deferred Income
Taxes 268
Other Liabilities 77
------
Total Liabilities of Discontinued
Operations $1,798
Disposal of CitiPower
On July 19, 2002, AEP, through a wholly owned subsidiary entered into an
agreement to sell CitiPower, a retail electricity and gas supply and
distribution subsidiary in Australia. AEP completed the sale on August 30, 2002
and received net cash of approximately $175 million and the buyer assumed
CitiPower debt of approximately $674 million. AEP recorded a net charge totaling
$125 million as of June 30, 2002. The charge included an impairment loss of $98
million on the remaining carrying value of an intangible asset related to a
distribution license for CitiPower. The remaining $27 million of net loss was
classified as a transitional goodwill impairment loss from the adoption of SFAS
142 (see Notes 2 and 3) and was recorded as a Cumulative Effect of Accounting
Change retroactive to January 1, 2002.
The loss on the sale of CitiPower increased $24 million to $149 million in the
second half of 2002 based on actual closing amounts and exchange rates.
CitiPower's results of operations have been reclassified as Discontinued
Operations in accordance with SFAS 144. The assets and liabilities of CitiPower
have been aggregated on the December 31, 2001, AEP balance sheet as Assets of
Discontinued Operations and Liabilities of Discontinued Operations. The major
classes of CitiPower's assets and liabilities of discontinued operations are:
December 31, 2001
-------------------
(in millions)
Assets:
Current Assets $ 138
Plant, Property and
Equipment, Net 495
Goodwill/Intangibles 466
Other Assets 23
------
Total Assets of
Discontinued
Operations $1,122
======
Liabilities:
Current Liabilities $ 83
Long-term Debt 612
Deferred Income Taxes 55
Other Liabilities 34
----
Total Liabilities of Discontinued
Operations
$784
Total revenues and pretax profit (loss) of the discontinued operations of
SEEBOARD and CitiPower were:
SEEBOARD
(in millions)
Revenues:
12 months ended
12/31/02 $ 694
12 months ended
12/31/01 1,451
12 months ended
12/31/00 1,596
Pretax Profit:
12 months ended
12/31/02 $ 180
12 months ended
12/31/01 104
12 months ended
12/31/00 91
CitiPower
(in millions)
Revenues:
12 months ended
12/31/02 $ 204
12 months ended
12/31/01 350
12 months ended
12/31/00 338
Pretax Profit (Loss):
12 months ended
12/31/02 $ (190)
12 months ended
12/31/01 (4)
12 months ended
12/31/00 20
Disposition of Texas REPs
In April 2002, AEP reached a definitive agreement, subject to regulatory
approval, to sell two of its Texas retail electric providers (REPs) to Centrica,
a provider of retail energy and other consumer services. PUCT regulatory
approval for the sale was obtained in December 2002. On December 23, 2002 AEP
sold to Centrica, the general partner interests and the limited partner
interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a base
purchase price paid in cash at closing and certain additional payments,
including a net working capital payment. Centrica paid a base purchase price of
$145.5 million which was based on a fair market value per customer established
by an independent appraiser and an agreed customer count. AEP recorded a net
gain totaling $83.7 million in Other Income. AEP (through TCC and TNC) will
provide Centrica with a power supply contract for the two REPs and back-office
services related to these customers for a two-year period. In addition, AEP
retained the right to share in earnings from the two REPs above a threshold
amount through 2006 in the event the Texas retail market develops increased
earnings opportunities. Under the Texas Legislation, REPs are subject to a
clawback liability if customer change does not attain thresholds required by the
legislation. AEP is responsible for a portion of such liability, if any, for the
period it operated the REPs in the Texas competitive retail market (January 1,
2002 through December 23, 2002). In addition, AEP retained responsibility for
regulatory obligations arising out of operations before closing. AEP's
wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an
up-front payment of approximately $30 million from Centrica associated with the
back-office service agreement, and MESC deferred its right to receive payment of
an additional amount of approximately $9 million to secure certain contingent
obligations. These prepaid service revenues were deferred on the books of MESC
to be amortized over the two-year term of the back office service agreement.
2001
In March 2001, CSWE, a subsidiary company, completed the sale of Frontera, a
generating plant that the FERC required to be divested in connection with the
merger of AEP and CSW. The sale proceeds were $265 million and resulted in an
after tax gain of $46 million.
In July 2001, AEP, through a wholly owned subsidiary, sold its 50% interest in a
120-megawatt generating plant located in Mexico. The sale resulted in an after
tax gain of approximately $11 million.
In July 2001, OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia
and agreed to purchase approximately 34 million tons of coal from the purchaser
of the mines through 2008. The sale is expected to have a nominal impact on the
results of operations and cash flows of OPCo and AEP.
In December 2001, AEP completed the sale of its ownership interests in the
Virginia and West Virginia PCS (personal communications services) Alliances for
stock, resulting in an after tax gain of approximately $7 million. During 2002,
due to decreasing market value of the shares, AEP reduced the value of them to
zero.
2000
In December 2000, AEP, through a wholly owned subsidiary, committed to negotiate
a sale of its 50% investment in Yorkshire, a U.K. electricity supply and
distribution company. As a result a $43 million writedown ($30 million after
tax) was recorded in the fourth quarter of 2000 to reflect the net loss from the
expected sale in the first quarter of 2001. The writedown is included in Other
Income on AEP's Consolidated Statements of Operations. On February 26, 2001 an
agreement to sell the Company's 50% interest in Yorkshire was signed. On April
2, 2001, following the approval of the buyer's shareholders, the sale was
completed without further impact on AEP's consolidated earnings.
In December 2000, CSW International, a subsidiary company sold its investment in
a Chilean electric company for $67 million. A net loss on the sale of $13
million ($9 million after tax) is included in Other Income, and includes $26
million ($17 million net of tax) of losses from foreign exchange rate changes
that were previously reflected in Accumulated Other Comprehensive Income. In the
second quarter of 2000 AEP management determined that the then existing decline
in market value of the shares was other than temporary. As a result the
investment was written down by $33 million ($21 million after tax) in June 2000.
The total loss from both the write down of the Chilean investment to market in
the second quarter and from the sale in the fourth quarter was $46 million ($30
million net of tax).
Discontinued Operations
The operations shown below, affecting AEP, were discontinued or classified as
held for sale in 2002. Results of operations of these businesses have been
reclassified as shown in the following table:
SEE-BOARD CitiPower Pushan Eastex Total
--------- --------- ------ ------ -----
(in millions)
2002 Revenue $ 694 $204 $57 $ 73 $1,028
2001 Revenue 1,451 350 57 - 1,858
2000 Revenue 1,596 338 57 - 1,991
2002 Earnings (Loss)
After Tax 96 (123) (7) (156) (190)
2001 Earnings
(Loss) After Tax 88 (6) 4 - 86
2000 Earnings (Loss)
After Tax 99 17 7 (1) 122
13. Asset Impairments and Investment Value Losses:
In 2002 AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.426 billion (consisting of approximately $866.6 million
related to Asset Impairments, $321.1 million related to Investment Value and
Other Impairment Losses, and $238.7 million related to Discontinued Operations)
that reflected downturns in energy trading markets, projected long-term
decreases in electricity prices, and other factors. These impairments exclude
the transitional impairment loss from adoption of SFAS142 (see Notes 2 and 3).
The categories of impairments included:
2002 Pre-Tax Estimated Loss
----
(in millions)
Asset Impairments Held for Sale $ 483.1
Asset Impairments Held and Used 651.4
Investment Value Losses 291.9
----------
Total $1,426.4
========
a. Assets Held for Sale
In 2002, AEP (and its registrant subsidiaries, as applicable) recorded the
following estimated loss on disposal of assets (including Goodwill) held for
sale:
2002 Pre-Tax
Assets Estimated Loss
Held for Sale on Disposal Business Registrant
------------- ----------- -------- ----------
(in millions)
Eastex $218.7 Wholesale AEP
Pushan Power 20.0 Other AEP
-------
Total Impairment Losses
Included in Discontinued
Operations $238.7
Telecommunication - AEPC/C3 $158.5 Other AEP
Newgulf Facility 11.8 Wholesale AEP
Nordic Trading 5.3 Wholesale AEP
Excess Equipment 23.9 Wholesale AEP
Excess Real Estate 15.7 Wholesale AEP
--------
Total Included in
Asset Impairment Losses $215.2
Telecommunications - AFN $ 13.8 Other AEP
Water Heater AEP, APCo, CSPCo,
Program 3.2 Wholesale I&M, KPCo and OPCo
Gas Power Systems 12.2 Wholesale AEP
--------
Total Included in
Investment Value
and Other Impairment
Losses $ 29.2
-------
Total-All Held for Sale
Losses $483.1
======
Eastex
In 1998, CSW began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, AEP requested that the FERC allow it to modify the
FERC Merger Order and substitute Eastex as a required divestiture under the
order, due to the fact that the agreed upon market-power related divestiture of
a plant in Oklahoma was no longer feasible. The FERC approved the request at the
end of September 2002. Subsequently, in the fourth quarter of 2002 AEP solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. A sale of assets is expected to be completed by the end of 2003
with an estimated pre-tax loss on sale of $218.7 million included in
Discontinued Operations in AEP's Consolidated Statements of Operations. The
estimated loss was based on the estimated fair value of the facility and
indicative bids by interested buyers.
Results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144 as shown in Note 12. The assets and
liabilities of Eastex have been included on AEP's Consolidated Balance Sheets as
held for sale. The major classes of assets and liabilities held for sale are:
2002 2001
---- ----
(in millions)
Assets:
Current Assets $15 $ -
Property, Plant and Equipment, Net - 217
Other Assets - 3
------ ------
Total Assets Held for Sale $15 $220
=== ====
Liabilities:
Current Liabilities $ 8 $ 5
Other Liabilities 4 1
----- ------
Total Liabilities Held for Sale $12 $ 6
=== ======
Pushan Power Plant
In the fourth quarter of 2002, AEP began active negotiations to sell its
interest in the Pushan Power Plant (Pushan) in Nanyang, China to the minority
interest partner. Negotiations are expected to be completed by the second
quarter of 2003 with an estimated pre-tax loss on disposal of $20.0 million,
based on an indicative price expression. The estimated pre-tax loss on disposal
is classified in Discontinued Operations in AEP's Consolidated Statements of
Operations.
Results of operations of Pushan have been reclassified as Discontinued
Operations in accordance with SFAS 144 as discussed in Note 12. The assets and
liabilities of Pushan have been classified on AEP's Consolidated Balance Sheets
as held for sale. The major classes of assets and liabilities held for sale are:
2002 2001
---- ----
(in millions)
Assets:
Current Assets $ 19 $ 17
Property, Plant and Equipment, Net 132 161
----- -----
Total Assets Held for Sale $151 $178
==== ====
Liabilities:
Current Liabilities $ 28 $ 27
Long-term Debt 25 30
Other Liabilities 26 24
------ -----
Total Liabilities Held for Sale $ 79 $ 81
===== =====
Telecommunications
AEP had developed businesses to provide telecommunication services to businesses
and to other telecommunication companies through broadband fiber optic networks
operated in conjunction with AEP's electric transmission and distribution lines.
The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the
difficult economic conditions in these businesses and the overall
telecommunications industry, and other operating problems, the AEP Board
approved in December 2002 a plan to cease operations of these businesses. AEP
took steps to market the assets of the businesses to potential interested buyers
in the fourth quarter of 2002. A number of potential buyers have made offers for
the assets of C3. Potential buyers have indicated interest in the assets of AFN.
A formal offering of the assets of AEPC will begin early in 2003. The complete
sale of all telecommunication assets is expected to be completed by the end of
2003 with an estimated pre-tax impairment loss of $158.5 million (related to
AEPC and C3) classified in Asset Impairments in AEP's Consolidated Statements of
Operations and an estimated pre-tax loss in value of the investment in AFN of
$13.8 million classified in Investment Value and Other Impairment Losses in
AEP's Consolidated Statements of Operations. The estimated losses are based on
indicative bids by potential buyers.
$6 million and $182 million of Property, Plant and Equipment, net of accumulated
depreciation of the telecommunication businesses have been classified on AEP's
Consolidated Balance Sheets as held for sale in 2002 and 2001, respectively.
Newgulf Facility
In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002 AEP began negotiations
with a likely buyer of the facility. A sale is now expected to be completed by
the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on
an indicative bid by the likely buyer. The estimated loss on disposal is
classified in Asset Impairments on AEP's Consolidated Statements of Operations.
Newgulf's Property, Plant and Equipment, net of accumulated depreciation, of $6
million in 2002 and $17 million in 2001 has been classified on AEP's
Consolidated Balance Sheets as held for sale.
Nordic Trading
In October 2002 AEP announced that its ongoing energy trading operations would
be centered around its generation assets. As a result, AEP took steps to exit
its coal, gas, and electricity trading activities in Europe, except for those
activities necessary to support the U.K. Generation operations. The Nordic
Trading business acquired earlier in 2002 (see Note 12) was made available for
sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3
million, consisted of impairment of goodwill of $4.0 million (see Note 3) and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments on AEP's Consolidated Statements of Operations.
Management's determination of a zero fair value was based on discussions with a
potential buyer. There are no assets and liabilities of Nordic Trading to be
classified on AEP's Consolidated Balance Sheets as held for sale.
Excess Equipment
In November 2002, as a result of a cancelled development project, AEP obtained
title to a surplus gas turbine generator. AEP has been unsuccessful in finding
potential buyers of the unit, including its own internal generation operators,
due to an over-supply of generation equipment available for sale. Sale of the
turbine is now projected before the end of 2003 with an estimated 2002 pre-tax
loss on disposal of $23.9 million, based on market prices of similar equipment.
The loss is included in Asset Impairments on AEP's Consolidated Statements of
Operations. The Other asset of $12 million in 2002 and $31 million in 2001 has
been classified on AEP's Consolidated Balance Sheets as held for sale.
Excess Real Estate
In the fourth quarter of 2002, AEP began to market an under-utilized office
building in Dallas, TX obtained through the merger with CSW. One prospective
buyer has executed an option to purchase the building. Sale of the facility is
projected by second quarter 2003 and an estimated 2002 pre-tax loss on disposal
of $15.7 million has been recorded, based on the option sale price. The
estimated loss is included in Asset Impairments on AEP's Consolidated Statements
of Operations. The Property asset of $18 million in 2002 and $36 million in 2001
has been classified on AEP's Consolidated Balance Sheets as held for sale.
Water Heater Program
AEP, APCo, CSPCo, I&M, KPCo and OPCo operated a program to lease electric water
heaters to residential and commercial customers until a decision was reached in
the fourth quarter of 2002 to discontinue the program and to offer the assets
for sale. Negotiations are underway with a qualified buyer, and sale of the
assets is projected by the end of the first quarter of 2003. AEP's estimated
2002 pre-tax loss on disposal of $3.20 million ($50 thousand for APCo, $615
thousand for CSPCo, $643 thousand for I&M, $11 thousand for KPCo, $1.757 million
for OPCo and $126 thousand for other AEP non-registrant subsidiaries) was based
on the expected contract sales price. The loss is included in Investment Value
and Other Impairment Losses on AEP's Consolidated Statements of Operations and
in Nonoperating Expenses on the statements of income of the registrant
subsidiaries. The assets and liabilities have been classified on AEP's
Consolidated Balance Sheets as held for sale. The major classes of assets held
for sale are:
2002 2001
---- ----
(in millions)
Assets:
Current Assets $ 1 $ 2
Property, Plant and Equipment, Net 38 48
---- ----
Total Assets Held for Sale $39 $50
=== ===
Gas Power Systems
AEP acquired in 2001 a 75% interest in a startup company seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. The
first quarter of 2002, AEP recognized a goodwill impairment loss of $12.2
million due to technological and operating problems (See Note 3). The loss was
recorded in Investment Value and Other Impairment Losses on AEP's Consolidated
Statements of Operations. The fair values of the remaining assets and
liabilities were excluded from AEP's Consolidated Balance Sheets as held for
sale, as the impact was insignificant. AEP's remaining interest was sold in
January 2003.
b. Assets Held and Used
In 2002, AEP recorded the following impairments related to assets (including
Goodwill) held and used to Asset Impairments on AEP's Consolidated Statements of
Operations:
Assets Business
Held and Used 2002 Pre-Tax Loss Segment Registrant
------------- ------------------ ------- ----------
(in millions)
U.K. Generation $548.7 Wholesale AEP
AEP Coal 59.9 Wholesale AEP
Texas Plants 38.1 Wholesale AEP and TNC
Ft. Davis Wind Farm
4.7 Wholesale AEP and TNC
-------
Total - ALL
Held and Used
Losses $51.4
=====
U.K. Generation Plants
In December 2001, AEP acquired two coal-fired generation plants (U.K.
Generation) in the U.K. for a cash payment of $942.3 million and assumption of
certain liabilities. Subsequently and continuing through 2002, wholesale U.K.
electric power prices declined sharply as a result of domestic over-capacity and
static demand. External industry forecasts and AEP's own projections made during
the fourth quarter of 2002 indicate that this situation may extend many years
into the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million, including a goodwill
impairment of $166.1 million as discussed in Note 3. The cash flow analysis used
a discount rate of 6% over the remaining life of the assets and reflected
assumptions for future electricity prices and plant operating costs. This
impairment loss is included in Asset Impairments on AEP's Consolidated
Statements of Operations.
AEP Coal
In October 2001, AEP acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and re-identified as "AEP Coal". During 2002 the coal operations suffered
a decline in forward prices and adverse mining factors that culminated in the
fourth quarter of 2002 and significantly reduced mine productivity and revenue.
Based on an extensive review of economically accessible reserves and other
factors, future mine productivity and production is expected to continue to be
below historical levels. In December 2002, a probability-weighted discounted
cash flow analysis of fair value of the mines was performed which indicated a
2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of
$3.6 million as discussed in Note 3. This impairment loss is included in Asset
Impairments on AEP's Consolidated Statements of Operations.
Texas Plants
In September 2002, AEP proposed closing 16 gas-fired power plants in the ERCOT
control area of Texas (8 TNC plants and 8 TCC plants). ERCOT indicated that it
may designate some of those plants as "reliability must run" (RMR) status. In
October ERCOT designated seven RMR plants (3 TNC plants and 4 TCC plants) and
approved AEP's plan to inactivate nine other plants (5 TNC plants and 4 TCC
plants). The process of moving the plants to inactive status took approximately
two months. Employees of the plants moved to inactive status (approximately 180)
were eligible for severance and outplacement services.
As a result of the decision to inactivate TNC plants, a write-down of utility
assets of approximately $34.2 million (pre-tax) was recorded in Asset
Impairments expense during the third quarter 2002 on AEP's and TNC's Statements
of Operations. The decision to inactivate the TCC plants resulted in a
write-down of utility assets of approximately $95.6 million (pre-tax), which was
deferred and recorded in Regulatory Assets during the third quarter 2002 in
AEP's Consolidated Balance Sheets (in Regulatory Assets Designated For or
Subject to Securitization on TCC's Consolidated Balance Sheets).
During the fourth quarter 2002, evaluations continued as to whether assets
remaining at the inactivated plants, including materials, supplies and fuel oil
inventories, could be utilized elsewhere within the AEP System. As a result of
such evaluations, TNC recorded an additional asset impairment charge to Asset
Impairments expense of $3.9 million (pre-tax) in the fourth quarter 2002. In
addition TNC recorded related inventory write-downs of $2.6 million [$1.2
million in Fuel and Purchased Energy: Electricity on AEP (Fuel Expense on TNC)
and $1.4 million in Maintenance and Other Operation expense on AEP (Other
Operation on TNC)]. Similarly, TCC recorded an additional asset impairment
write-down of $6.7 million (pre-tax), which was deferred and recorded in
Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to
Securitization on TCC's Consolidated Balance Sheets) in the fourth quarter 2002.
TCC also recorded related inventory write-downs of $14.9 million which was
deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets
Designated For or Subject to Securitization on TCC's Consolidated Balance
Sheets) in the fourth quarter 2002.
The total Texas plant asset impairment of $38.1 million in 2002 (all related to
TNC) is included in Asset Impairments on AEP's and TNC's Consolidated Statements
of Operations.
RMR plants are required to ensure the reliability of the power grid, even if
electricity from those plants is not required to meet market needs. ERCOT and
AEP negotiated interim contracts for the seven RMR plants through December 2003,
however, ERCOT has the right to terminate the plants from RMR status upon 90
days written notice.
In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either inactivated or designated as RMR status. See
Texas Restructuring section of the "Customer Choice and Industry Restructuring"
Note 8 for further discussion of the divestiture plan and anticipated timeline.
Ft. Davis Wind Farm
In the 1990's, CSW developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 AEP engineering
staff determined that operation of the facility was no longer technically
feasible and the lease of the underlying site should not be renewed. Dismantling
of the facility will be complete by the end of 2003 with an estimated 2002
pre-tax loss on abandonment of $4.7 million. The loss was recorded in Asset
Impairments on AEP's Consolidated Statements of Operations and TNC's Statements
of Operations. The facility will continue to be classified as held and used
until disposal is complete.
c. Investment Values
In 2002, AEP recorded the following declines in fair value on investments
accounted for under APB 18 that were considered to be other than temporarily
impaired as shown in the table below:
Investment Value
Impairment 2002 Pre-Tax Business
Loss Items Estimated Loss Segment Registrant
---------- -------------- ------- ----------
(in millions)
Grupo Rede Investment - Brazil $217.0 Other AEP
South Coast Power 63.2 Other AEP
Misc. Technology Investments 11.7 Other AEP
------
Total $291.9
Grupo Rede Investment
In December 2002, AEP recorded an other than temporary impairment totaling
$141.0 million ($217.0 million net of federal income tax benefit of $76.0
million) of its 44% equity investment in Vale and its 20% equity interest in
Caiua, both Brazilian electric operating companies (referred to as Grupo Rede).
This amount is included in Investment Value and Other Impairment Losses on AEP's
Consolidated Statements of Operations. As of September 30, 2002, AEP had not
recognized its cumulative equity share of operating and foreign currency
translation losses of approximately $88 million and $105 million, respectively,
due to the existence of a put option that permits AEP to require Grupo Rede to
purchase our equity at a minimum price equal to the U.S. dollar equivalent of
the original purchase price. In January 2002 AEP evaluated through an
independent credit assessment the ability of Grupo Rede to fulfill its
responsibilities under the put option and concluded that the carrying value of
the original investment was reasonable.
During 2002, there has been a continuing decline in the Brazilian power industry
and the value of the local currency. Events in the fourth quarter of 2002 led us
to change our view that Grupo Rede would be able to fulfill its responsibilities
under the put option. These events included two downgrades of Caiua debt by
Moody's, resulting in a rating of Caa1. Caiua is an intermediate holding company
which owns substantially all of the utility companies in the Grupo Rede system.
The downgrading of Caiua's credit ratings to a level well below investment grade
casts significant doubt on the ability of Grupo Rede to honor the put option.
Grupo Rede is in the process of restructuring some of its debt s, and as a
condition for participating in the restructuring, during November 2002 a
creditor of Grupo Rede requested that AEP agree not to exercise the put option
prior to March 31, 2007. AEP agreed and in exchange received an extension of the
put option from the previous end date of 2009 through 2019. Based on the factors
noted above, AEP could no longer reasonably believe that our investment could be
recovered, resulting in the recording of the impairment.
South Coast Power Investment
South Coast Power is a 50% owned joint venture that was formed in 1996 to build
and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K..
South Coast Power is subject to the same adverse wholesale electric power rates
described for U.K. Generation above. A December 2002 projected cash flow
estimate of the fair value of the investment indicated a 2002 pre-tax other than
temporary impairment of the equity interest (which included the fair value of
supply contracts held by South Coast Power and accounted for in accordance with
SFAS 133) in the amount of $63.2 million. This loss of investment value is
included in Investment Value and Other Impairment Losses on AEP's Consolidated
Statements of Operations.
Technology Investments
AEP previously made investments totaling $11.7 million in four early-stage or
startup technologies involving pollution control and procurement. An analysis in
December 2002 of the viability of the underlying technologies and the projected
performance of the investee companies indicated that the investments were
unlikely to be recovered, and an other than temporary impairment of the entire
amount of the equity interest under APB 18 was recorded. The loss of investment
value is included in Investment Value and Other Impairment Losses on AEP's
Consolidated Statements of Operations.
14. Benefit Plans:
Pension and Other Postretirement Benefits
In the U.S. AEP sponsors two qualified pension plans and two nonqualified
pension plans. Substantially all employees in the U.S. are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. Other
postretirement benefit (OPEB) plans are sponsored by the AEP System to provide
medical and death benefits for retired employees in the U.S.
AEP also has a foreign pension plan for employees of AEP Energy Services U.K.
Generation Limited (Genco) in the U.K. Genco employees participate in their
existing pension plan acquired as part of AEP's purchase of two generation
plants in the U.K. in December 2001.
The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending
December 31, 2002, and a statement of the funded status as of December 31 for
both years:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Reconciliation of Benefit
Obligation:
Obligation at January 1 $3,292 $3,161 $ 1,645 $1,668
Service Cost 72 69 34 30
Interest Cost 241 232 114 114
Participant Contributions - - 13 8
Plan Amendments (2) - - 7 (a)
Actuarial (Gain) Loss 258 121 152 192
Divestitures - - - (287) (b)
Benefit Payments (278) (291) (81) (88)
Curtailments - - - 1
------ ------ ------- ------
Obligation at December 31 $3,583 $3,292 $ 1,877 $1,645
====== ====== ======= ======
Reconciliation of Fair Value
of Plan Assets:
Fair Value of Plan Assets at
January 1 $3,438 $3,911 $ 711 $ 704
Actual Return on Plan Assets (371) (182) (57) (31)
Company Contributions 6 - 137 118
Participant Contributions - - 13 8
Benefit Payments (278) (291) (81) (88)
------ ------ ------- ------
Fair Value of Plan Assets at
December 31 $2,795 $3,438 $ 723 $ 711
====== ====== ======= ======
Funded Status:
Funded Status at December 31 $ (788) $ 146 $(1,154) $ (934)
Unrecognized Net Transition
(Asset) Obligation (7) (15) 233 263
Unrecognized Prior-Service Cost (13) (12) 6 7
Unrecognized Actuarial
(Gain) Loss 1,020 35 896 649
------ ------ ------- ------
Prepaid Benefit (Accrued
Liability) $ 212 $ 154 $ (19) $ (15)
====== ====== ======= ======
(a) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line.
(b) Related to the sale of Central Ohio Coal Company, Southern Ohio Coal Company
and Windsor Coal Company.
The following table provides the amounts for prepaid benefit costs and accrued
benefit liability recognized in the Consolidated Balance Sheets as of December
31 of both years. The amounts for additional minimum liability, intangible asset
and Accumulated Other Comprehensive Income for 2001 and 2002 were recorded in
2002.
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2002 2001
---- ---- ---- ----
(in millions)
Prepaid Benefit Costs $ 255 $ 205 $ - $ 1
Accrued Benefit Liability (44) (51) (19) (16)
Additional Minimum Liability (944) (15) N/A N/A
Intangible Asset 45 9 N/A N/A
Accumulated Other
Comprehensive Income 900 6 N/A N/A
----- ----- ---- ------
Net Asset (Liability) $ 212 $ 154 $(19) $ (15)
===== ===== ==== =====
Other Comprehensive (Income)
Expense Attributable to
Change in Additional Pension
Liability Recognition $ 894 $(4) N/A N/A
===== === ==== ======
N/A = Not Applicable
The value of our qualified plans' assets has decreased from $3.438 billion at
December 31, 2001 to $2.795 billion at December 31, 2002. The qualified plans
paid $272 million in benefits to plan participants during 2002 (nonqualified
plans paid $6 million in benefits). The investment returns and declining
discount rates have changed the status of our qualified plans from overfunded
(plan assets in excess of projected benefit obligations) by $146 million at
December 31, 2001 to an underfunded position (plan assets are less than
projected benefit obligations) of $788 million at December 31, 2002. Due to the
qualified plans currently being underfunded, the Company recorded a charge to
Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax
Asset of $315 million, offset by a Minimum Pension Liability of $662 million and
reduction to prepaid costs and intangible assets of $238 million. The charge to
OCI does not affect earnings or cash flow. The OCI charge for each AEP
subsidiary registrant is recorded in Minimum Pension Liability in the respective
registrant's Consolidated Statements of Comprehensive Income. Also, because of
the recent reductions in the funded status of our qualified plans, we expect to
make cash contributions to our qualified plans of approximately $66 million in
2003 increasing to approximately $108 million per year by 2005.
The AEP System's qualified pension plans had accumulated benefit obligations in
excess of plan assets of $661 million at December 31, 2002.
The AEP System's nonqualified pension plans had accumulated benefit obligations
in excess of plan assets of $72 million at December 31, 2002 and $66 million at
December 31, 2001. There are no assets in the nonqualified plans.
The AEP System's OPEB plans had accumulated benefit obligations in excess of
plan assets of $1,154 million and $934 million at December 31, 2002 and 2001,
respectively.
The Genco pension plan had $7 million and $10 million at December 31, 2002 and
2001, respectively, of accumulated benefit obligations in excess of plan assets.
The following table provides the components of AEP's net periodic benefit cost
(credit) for the plans for fiscal years 2002, 2001 and 2000:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
(in millions)
Service Cost $ 72 $ 69 $ 60 $ 34 $ 30 $ 29
Interest Cost 241 232 227 114 114 106
Expected Return on Plan Assets (337) (338) (321) (62) (61) (57)
Amortization of
Transition (Asset) Obligation (9) (8) (8) 29 30 41
Amortization of Prior-service
Cost (1) - 13 - - -
Amortization of Net Actuarial
(Gain) Loss (10) (24) (39) 27 18 4
---- ----- ----- ---- ---- ----
Net Periodic Benefit Cost
(Credit) (44) (69) (68) 142 131 123
Curtailment Loss (a) - - - - 1 79
---- ----- ----- ---- ---- ----
Net Periodic Benefit
Cost (Credit) After
Curtailments $ (44) $ (69) $ (68) $142 $132 $202
===== ===== ===== ==== ==== ====
(a) Curtailment charges were recognized during 2000 for the shutdown of
Central Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal
Company.
The following table provides the net periodic benefit cost (credit) for the
plans by the following AEP registrant and other non-registrant subsidiaries for
fiscal years 2002, 2001 and 2000:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
APCo $ (9,988) $(13,645) $(14,047) $ 25,107 $ 22,810 $ 22,139
CSPCo (8,328) (10,624) (10,905) 11,494 10,328 9,643
I&M (4,206) (7,805) (8,565) 17,608 15,077 14,155
KPCo (1,406) (1,922) (2,075) 2,986 2,438 2,364
OPCo (11,360) (14,879) (15,041) 22,608 34,444 116,205
PSO (3,819) (2,480) (2,196) 8,436 6,187 4,277
SWEPCo (2,245) (3,051) (2,606) 8,371 6,399 4,152
TCC (4,786) (3,411) (2,986) 10,733 8,214 6,656
TNC (1,104) (1,644) (1,585) 4,798 3,729 2,929
Other Non-Registrant
Subsidiaries 3,657 (9,139) (7,546) 29,722 22,278 19,798
-------- -------- -------- -------- -------- --------
Total $(43,585) $(68,600) $(67,552) $141,863 $131,904 $202,318
======== ======== ======== ======== ======== ========
The weighted-average assumptions as of December 31, used in the measurement of
AEP's benefit obligations are shown in the following tables:
U.S. U.S.
Pension Plans OPEB Plans
------------- ----------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
% % % % % %
Discount Rate 6.75 7.25 7.50 6.75 7.25 7.50
Expected Return on
Plan Assets 9.00 9.00 9.00 8.75 8.75 8.75
Rate of Compensation
Increase 3.7 3.7 3.2 N/A N/A N/A
In determining the discount rate in the calculation of future pension
obligations we review the interest rates of long-term bonds that receive one of
the two highest ratings given by a recognized rating agency. As a result of a
decrease in this benchmark rate during 2002, we determined that a decrease in
our discount rate from 7.25% at December 31, 2001 to 6.75% at December 31, 2002
was appropriate.
For OPEB measurement purposes, a 10% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2003. The rate was assumed
to decrease gradually each year to a rate of 5% through 2008 and remain at that
level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:
1% Increase 1% Decrease
----------- -----------
(in millions)
Effect on total service
and interest cost
components of net
periodic postretirement
health care benefit cost $ 21 $ (17)
Effect on the health care
component of the
accumulated
postretirement
benefit obligation 237 (193)
AEP Savings Plans
AEP sponsors various defined contribution retirement savings plans eligible to
substantially all non-United Mine Workers of America (UMWA) U.S. employees.
These plans include features under Section 401(k) of the Internal Revenue Code
and provide for company matching contributions. Beginning in 2001, AEP's
contributions to the two largest plans increased to 75 cents for every dollar of
the first 6% of eligible employee compensation from the previous rate of 50
cents. The cost for contributions to these plans totaled $60.1 million in 2002,
$55.6 million in 2001 and $36.8 million in 2000.
The following table provides the cost for contributions to the savings plans by
the following AEP registrant and other non-registrant subsidiaries for fiscal
years 2002, 2001 and 2000:
2002 2001 2000
---- ---- ----
(in thousands)
APCo $ 6,722 $7,031 $ 3,988
CSPCo 2,784 2,789 1,638
I&M 8,039 7,833 4,231
KPCo 1,043 1,016 544
OPCo 5,785 6,398 3,713
PSO 2,260 2,235 2,306
SWEPCo 2,765 2,776 2,880
TCC 3,054 3,046 3,161
TNC 1,574 1,558 1,708
Other Non-
Registrant
Subsidiaries 26,094 20,869 12,677
------- ------- ------
Total $60,120 $55,551 $36,846
======= ======= =======
On January 1, 2003, the two major AEP Savings Plans merged into a single plan.
Other UMWA Benefits
AEP and OPCo provide UMWA pension, health and welfare benefits for certain
unionized mining employees, retirees, and their survivors who meet eligibility
requirements. The benefits are administered by UMWA trustees and contributions
are made to their trust funds. Contributions are expensed as paid as part of the
cost of active mining operations and were not material in 2002, 2001 and 2000.
In July 2001, OPCo sold certain coal mines in Ohio and West Virginia.
15. Stock-Based Compensation:
The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) was
approved by shareholders at AEP's annual meeting in 2000 and authorizes the use
of 15,700,000 shares of AEP common stock for various types of stock-based
compensation awards, including stock option awards, to key employees. The Plan
was adopted in 2000.
Under the Plan, the exercise price of all stock option grants must equal or
exceed the market price of AEP's common stock on the date of grant. AEP
generally grants options that have a ten-year life and vest, subject to the
participant's continued employment, in approximately equal 1/3 increments on
January 1st following the first, second and third anniversary of the grant date.
CSW maintained a stock option plan prior to the merger with AEP in 2000.
Effective with the merger, all CSW stock options outstanding were converted into
AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP
stock option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. Outstanding CSW stock options will continue in effect until all
options are exercised, cancelled or expired. Under the CSW stock option plan,
the option price was equal to the fair market value of the stock on the grant
date. All CSW options fully vested upon the completion of the merger and expire
10 years after their original grant date.
A summary of AEP stock option transactions in fiscal periods 2002, 2001 and
2000 is as follows:
2002 2001 2000
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Options Exercise Options Exercise Options Exercise
(in thousands) Price (in thousands) Price (in thousands) Price
Outstanding at
beginning of year 6,822 $37 6,610 $36 825 $40
Granted 2,923 $27 645 $45 6,046 $36
Exercised (600) $36 (216) $38 (26) $36
Forfeited (358) $41 (217) $37 (235) $39
----- ----- -----
Outstanding at
end of year 8,787 $34 6,822 $37 6,610 $36
===== ===== =====
Options exercisable
at end of year 2,481 $36 395 $43 588 $41
===== === ===
Weighted average Exercise price of options:
-Granted above Market Price $27 N/A N/A
-Granted at Market Price $27 $45 $36
The following table summarizes information about AEP stock options outstanding
at December 31, 2002:
Options Outstanding
- ----------------------------------------------
Range of
Exercise Number Life in Exercise
Prices Outstanding Years Price
- ---------------------------------------------
$27.06-35.625 8,047,058 8.4 $ 32.54
40.69-49.00 739,483 7.1 44.84
- ---------------------------------------------
$27.06-49.00 8,786,541 8.3 $ 33.58
- ---------------------------------------------
Options Exercisable
Range of
Exercise Number Weighted-Average
Prices Outstanding Exercise Price
$27.06-35.625 2,230,000 $35.51
40.69-49.00 251,327 43.66
- ---------------------------------------------
$27.06-49.00 2,481,327 $36.33
- ---------------------------------------------
If compensation expense for stock options had been determined based on the fair
value at the grant date, AEP net income and earnings per share would have been
the pro forma amounts shown in the following table:
- -------------------------------------------------------------
2002 2001 2000
---- ---- ----
(in millions
except per share amounts)
Net (loss) income:
As reported $ (519) $ 971 $ 267
Pro forma (528) 959 264
Basic (loss) earnings per share:
As reported $(1.57) $3.01 $0.83
Pro forma (1.59) 2.98 0.82
Diluted (loss) earnings per share:
As reported $(1.57) $3.01 $0.83
Pro forma (1.59) 2.97 0.82
The proceeds received from exercised stock options are included in common stock
and paid-in capital.
The pro forma amounts are not representative of the effects on reported net
income for future years.
The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used to estimate the fair value of AEP options granted:
2002 2001 2000
- -------------------------------------------------------------
Risk Free Interest
Rate 3.53% 4.87% 5.02%
Expected Life 7 years 7 years 7 years
Expected Volatility 29.78% 28.40% 24.75%
Expected Dividend
Yield 6.15% 6.05% 6.02%
Weighted average fair value of options:
-Granted above
Market Price $4.58 N/A N/A
-Granted at Market Price
$4.37 $8.01 $5.50
- ---------------------------- ---------- ---------- ----------
16. Business Segments:
In 2000, AEP reported the following four business segments: Domestic Electric
Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and Other.
With this structure, our regulated domestic utility companies were considered
single, vertically-integrated units, and were reported collectively in the
Domestic Electric Utilities segment.
In 2001 and 2002, we moved toward a goal of functionally and structurally
separating our businesses. The ensuing realignment of our operations resulted in
our current business segments, Wholesale, Energy Delivery and Other. The
business activities of each of these segments are as follows:
Wholesale
o Generation of electricity for sale to retail and wholesale customers
o Gas pipeline and storage services
o Marketing and trading of electricity, gas, coal and other commodities
o Coal mining, bulk commodity barging operations and other energy
supply related businesses
Energy Delivery
o Domestic electricity transmission
o Domestic electricity distribution
Other
o Energy services
Segment results of operations for the twelve months ended December 31, 2002,
2001 and 2000 are shown below. These amounts include certain estimates and
allocations where necessary.
We have used earnings before interest and income taxes (EBIT) as a measure of
segment operating performance. The EBIT measure is total operating revenues net
of total operating expenses and other income and deductions from income. It
differs from net income in that it does not take into account interest expense,
income taxes and the effect of discontinued operations, extraordinary items and
the cumulative effect of a change in accounting principle. EBIT is believed to
be a reasonable gauge of results of operations. By excluding interest expense
and income taxes, EBIT does not give guidance regarding the demand of debt
service or other interest requirements, or tax liabilities or taxation rates.
The effects of interest expense and taxes on overall corporate performance can
be seen in the Consolidated Statements of Operations. By excluding discontinued
operations, extraordinary items, and the cumulative effect of changes in
accounting principles, EBIT gives more focused guidance on segment operating
performance.
Energy Reconciling AEP
Year Wholesale Delivery Other Adjustments Consolidated
- ---- --------- -------- ----- ----------- ------------
(in millions)
2002
Revenues from:
External unaffiliated
customers $10,988 $ 3,551 $ 16 $ - $14,555
Transactions with other
operating segments 2,314 20 46 (2,380) -
Segment EBIT 645 970 (549) - 1,066
Depreciation, depletion and
amortization expense 842 519 16 - 1,377
Total assets 22,622 11,624 248 247(a) 34,741
Investments in equity method
subsidiaries 115 - 57 - 172
Gross property additions 1,072 638 12 - 1,722
2001
Revenues from:
External unaffiliated
customers $ 9,297 $ 3,356 $ 114 $ - $12,767
Transactions with other
operating segments 2,708 20 1,155 (3,883) -
Segment EBIT 1,302 986 42 - 2,330
Depreciation, depletion and
amortization expense 597 632 14 - 1,243
Total assets 21,947 12,455 220 4,675(a) 39,297
Investments in equity method
subsidiaries 242 - 370 - 612
Gross property additions 610 844 200 - 1,654
2000
Revenues from:
External unaffiliated
customers $ 7,834 $3,174 $ 105 $ - $11,113
Transactions with other
operating segments 1,726 2 750 (2,478) -
Segment EBIT 686 1,017 89 - 1,792
Depreciation, depletion and
amortization expense 556 506 29 - 1,091
Total assets 24,172 14,876 2,625 4,960(a) 46,633
Investments in equity method
subsidiaries 140 - 296 - 436
Gross property additions 366 961 141 - 1,468
(a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or
Assets of Discontinued Operations
Of the registrant operating company subsidiaries, all of the registrant
subsidiaries except AEGCo have two business segments. The segment results for
each of these subsidiaries are reported in the table below. AEGCo has one
segment, a wholesale generation business. AEGCo's results of operations are
reported in AEGCo's financial statements.
Twelve Months Ended Twelve Months Ended
December 31, 2002 December 31, 2001
----------------- -----------------
Segment Segment Total
Revenues EBIT Total Assets Revenues EBIT Assets
-------- ------- ------------ -------- ------- ------
(in thousands) (in thousands)
Wholesale Segment
APCo $1,220,381 $215,735 $2,586,966 $1,189,223 $164,844 $2,505,877
CSPCo 907,882 282,974 1,762,074 867,100 232,372 1,742,328
I&M 1,205,043 42,410 3,160,575 1,212,587 117,396 3,027,509
KPCo 246,629 6,568 591,655 247,842 4,935 507,516
OPCo 1,523,452 364,071 2,861,415 1,545,392 240,128 2,820,995
PSO 518,100 34,322 840,374 695,123 52,086 827,235
SWEPCo 736,484 70,547 1,082,251 768,322 82,409 1,127,331
TCC 1,135,946 395,060 3,117,447 1,265,655 303,966 2,847,743
TNC 377,387 (58,930) 376,308 387,422 7,930 371,031
Energy Delivery Segment
APCo $ 594,089 $217,360 $2,040,881 $ 595,036 $213,733 $1,976,908
CSPCo 492,278 63,071 991,166 483,219 130,503 980,060
I&M 321,721 170,342 1,426,616 314,410 111,206 1,366,553
KPCo 132,054 51,697 573,021 131,183 54,033 491,532
OPCo 589,673 71,225 1,595,617 552,713 118,261 1,573,078
PSO 275,547 69,543 936,316 261,877 79,787 921,676
SWEPCo 348,236 107,081 1,126,424 333,004 107,197 1,173,345
TCC 554,547 148,918 2,238,991 473,182 109,587 2,045,287
TNC 73,353 53,995 500,867 169,036 33,226 493,844
Registrant Subsidiaries
Company Total
APCo $1,814,470 $433,095 $4,627,847 $1,784,259 $378,577 $4,482,785
CSPCo 1,400,160 346,045 2,753,240 1,350,319 362,875 2,722,388
I&M 1,526,764 212,752 4,587,191 1,526,997 228,602 4,394,062
KPCo 378,683 58,265 1,164,676 379,025 58,968 999,048
OPCo 2,113,125 435,296 4,457,032 2,098,105 358,389 4,394,073
PSO 793,647 103,865 1,776,690 957,000 131,873 1,748,911
SWEPCo 1,084,720 177,628 2,208,675 1,101,326 189,606 2,300,676
TCC 1,690,493 543,978 5,356,438 1,738,837 413,553 4,893,030
TNC 450,740 (4,935) 877,175 556,458 41,156 864,875
Twelve Months Ended
December 31, 2000
-------------------
Revenues Segment EBIT Total Assets
-------- ------------ ------------
(in thousands)
Wholesale Segment
APCo $1,184,335 $154,525 $3,674,081
CSPCo 906,363 235,860 2,481,594
I&M 1,177,190 (146,297) 3,978,360
KPCo 268,529 22,379 759,228
OPCo 1,672,744 289,084 3,976,532
PSO 711,274 54,072 1,011,474
SWEPCo 773,324 27,055 1,302,611
TCC 1,291,588 273,650 3,182,202
TNC 394,860 13,910 466,539
Energy Delivery Segment
APCo $574,918 $191,560 $2,898,514
CSPCo 398,046 81,896 1,395,897
I&M 311,019 126,241 1,795,748
KPCo 121,346 49,770 735,315
OPCo 467,587 138,418 2,217,443
PSO 245,124 85,524 1,126,949
SWEPCo 344,950 129,842 1,355,778
TCC 478,814 136,069 2,285,499
TNC 176,204 50,201 620,965
Registrant Subsidiaries
Company Total
APCo $1,759,253 $346,085 $6,572,595
CSPCo 1,304,409 317,756 3,877,491
I&M 1,488,209 (20,056) 5,774,108
KPCo 389,875 72,149 1,494,543
OPCo 2,140,331 427,502 6,193,975
PSO 956,398 139,596 2,138,423
SWEPCo 1,118,274 156,897 2,658,389
TCC 1,770,402 409,719 5,467,701
TNC 571,064 64,111 1,087,504
17. Risk Management, Financial
Instruments and Derivatives:
Risk Management
We are subject to market risks in our day to day operations. Our risk policies
have been reviewed with the Board of Directors, approved by a Risk Executive
Committee and are administered by the Chief Risk Officer. The Risk Executive
Committee establishes risk limits, approves risk policies, assigns
responsibilities regarding the oversight and management of risk and monitors
risk levels. This committee receives daily, weekly, and monthly reports
regarding compliance with policies, limits and procedures. The committee meets
monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. of
Market Risk Oversight, and senior financial and operating managers.
The risks and related strategies that management can employ are:
Risk Description Strategy
- ---- ----------- --------
Price Risk Volatility in Trading and
commodity prices hedging
Interest Rate Risk Changes in
interest rates Hedging
Foreign Exchange Fluctuations in
Risk foreign currency Trading and
rates hedging
Credit Risk Non-performance Guarantees
on contracts and
with collateral
counterparties
We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree other commodities and as a result we are
subject to price risk. The amount of risk taken by the traders is controlled by
the management of the trading operations and the Chief Risk Officer and his
staff. If the risk from trading activities exceeds certain pre-determined
limits, the positions are modified or hedged to reduce the risk to be within the
limits unless specifically approved by the Risk Executive Committee.
AEP is exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by a settlement agreement in
Michigan, capped in Indiana and fixed (subject to future commission action) in
West Virginia. To the extent all fuel supply for the generating units in these
states is not under fixed price long-term contracts, AEP is subject to market
price risk. AEP continues to be protected against market price changes by active
fuel clauses in Arkansas, Kentucky, Louisiana, Oklahoma, Virginia and the SPP
area of Texas.
We enter into currency and interest rate forward and swap transactions to hedge
the currency and interest rate exposures created by commodity transactions.
These transactions are marked-to-market to match the change in value in the
transactions they hedge which are also marked-to-market. We employ forward
contracts as cash flow hedges and swaps as cash flow or fair value hedges to
mitigate changes in interest rates or fair values on Short-Term Debt and
Long-term Debt when management deems it necessary. We do not hedge all interest
rate risk.
We employ cash flow forward hedge contracts to lock-in prices on transactions
denominated in foreign currencies where deemed necessary. International
subsidiaries use currency swaps to hedge exchange rate fluctuations in debt
denominated in foreign currencies. We do not hedge all foreign currency
exposure.
Our open trading contracts, including structured transactions, are
marked-to-market daily using the price model and price curve(s) corresponding to
the instrument. Forwards, futures and swaps are generally valued by subtracting
the contract price from the market price and then multiplying the difference by
the contract volume and adjusting for net present value and other impacts.
Significant estimates in valuing such contracts include forward price curves,
volumes, seasonality, weather, and other factors.
Forwards and swaps are valued based on forward price curves which represent a
series of projected prices at which transactions can be executed in the market.
The forward price curve includes the market's expectations for prices of a
delivered commodity at that future date. The forward price curve is developed
from the market bid price, which is the highest price which traders are willing
to pay for a contract, and the ask or offer price, which is the lowest price
traders are willing to receive for selling a contract.
Option contracts, consisting primarily of options on forwards and spread
options, are valued using models, which are variations on Black-Scholes option
models. The market-related inputs are the interest rate curve, the underlying
commodity forward price curve, the implied volatility curve and the implied
correlation curve. Volatility and correlation prices may be quoted in the
market. Significant estimates in valuing these contracts include forward price
curves, volumes, and other volatilities.
Futures and options traded on exchanges (primarily oil and gas on NYMEX) are
valued at the exchange price.
Electricity and gas markets in particular have primary trading hubs or delivery
points/regions and less liquid secondary delivery points. In North American
natural gas markets, the primary delivery points are generally traded from Henry
Hub, Louisiana. The less liquid gas or power trading points may trade as a
spread (based on transportation costs, constraints, etc.) from the nearest
liquid trading hub. Also, some commodities trade more often and therefore are
more liquid than others. For example, peak electricity is a more liquid product
than off-peak electricity. Henry Hub gas trades in monthly blocks for up to 36
months and after that only trades in seasonal or calendar blocks. When this
occurs, we use our best judgment to estimate the curve values. The value used
will be based on various factors such as last trade price, recent price trend,
product spreads, location spreads (including transportation costs), cross
commodity spreads (e.g., heat rate conversion of gas to power), time spreads,
cost of carry (e.g., cost of gas storage), marginal production cost, cost of new
entrant capacity, and alternative fuel costs. Also, an energy commodity
contract's price volatility generally increases as it approaches the delivery
month. Spot price volatility (e.g., daily or hourly prices) can cause contract
values to change substantially as open positions settle against spot prices.
When a portion of a curve has been estimated for a period of time and market
changes occur, assumptions are updated to align the curve to the market. All
fair value amounts are net of adjustments for items such as credit quality of
the counterparty (credit risk) and liquidity risk.
We also mark-to-market derivatives that are not trading contracts in accordance
with generally accepted accounting principles. There may be unique models for
these transactions, but the curves the Company inputs into the models are the
same forward curves, which are described above.
We have developed independent controls to evaluate the reasonableness of our
valuation models and curves. However, there are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. Therefore, there could be a significant favorable or adverse effect
on future results of operations and cash flows if market prices at settlement
differ from the price models and curves.
Results of Risk Management Activities
The amounts of net revenue margins (sales less purchases) in 2002, 2001, and
2000 for trading activities were:
2002 2001 2000
---- ---- ----
(in millions)
Net Revenue
Margins $53 $402 $233
The amounts of revenues recorded in 2002, 2001 and 2000 for the registrant
subsidiaries were:
2002 2001 2000
---- ---- ----
(in thousands)
APCo $29,044 $ 52,871 $ 27,924
CSPCo 24,503 36,120 16,999
I&M 11,833 19,130 26,575
KPCo 3,801 6,150 10,704
OPCo 39,114 43,789 26,840
PSO (1,357) (7,345) 5,233
SWEPCo (4,999) 2,317 1,562
TCC (7,708) 10,500 (1,752)
TNC (1,098) 1,508 222
------- -------- --------
Total $93,133 $165,040 $114,307
======= ======== ========
The fair value of open trading contracts that are marked-to-market are based on
management's best estimates using over-the-counter quotations and exchange
prices for short-term open trading contracts, and internally developed price
curves for open long-term trading contracts. The following table does not
reflect derivative contracts designated as hedges or firm transmission rights
contracts. As a result, the totals will not agree to the Consolidated Balance
Sheets. The fair values of trading contracts at December 31 are:
2002 2001
------------------ -------------------
Fair Fair
Value Value
(in millions) (in millions)
Trading Assets
Electricity and Other
Physicals $ 846 $ 966
Financials 226 170
------ -------
Total Trading Assets $1,072 $ 1,136
====== =======
Gas
Physicals $ 105 $ 196
Financials 685 1,587
------ -------
Total Trading Assets $ 790 $ 1,783
====== =======
Trading Liabilities
Electricity and Other
Physicals $ (534) $ (760)
Financials (126) (87)
------ -------
Total Trading Liabilities $ (660) $ (847)
====== =======
Gas
Physicals $ (191) $ (38)
Financials (761) (1,586)
------ -------
Total Trading Liabilities $ (952) $(1,624)
====== =======
The fair values of trading contracts for the registrant subsidiaries at December
31 are:
2002 2001
----------------- -----------------
Fair Fair
Value Value
(in thousands) (in thousands)
APCo
Trading Assets
Electricity and Other
Physicals $ 168,687 $ 217,914
Financials 39,585 39,466
Trading Liabilities
Electricity and Other
Physicals $(100,045) $(164,624)
Financials (11,375) (17,055)
CSPCo
Trading Assets
Electricity and Other
Physicals $ 113,397 $ 133,425
Financials 26,611 24,206
Trading Liabilities
Electricity and Other
Physicals $ (67,244) $ (98,749)
Financials (7,647) (10,433)
I&M
Trading Assets
Electricity and Other
Physicals $ 121,706 $ 165,162
Financials 28,474 26,630
Trading Liabilities
Electricity and Other
Physicals $ (70,061) $(117,795)
Financials (9,258) (12,652)
2002 2001
---------------- ------------------
Fair Fair
Value Value
(in thousands) (in thousands)
KPCo
Trading Assets
Electricity and Other
Physicals $ 43,532 $ 53,651
Financials 10,216 9,732
Trading Liabilities
Electricity and Other
Physicals $ (25,815) $ (46,476)
Financials (2,935) (4,178)
OPCo
Trading Assets
Electricity and Other
Physicals $ 158,473 $ 180,989
Financials 35,304 32,997
Trading Liabilities
Electric and Other
Physicals $ (89,526) $(132,603)
Financials (10,145) (15,937)
PSO
Trading Assets
Electricity
Physicals $ 8,165 $ 47,613
Trading Liabilities
Electricity
Physicals $ (4,620) $ (45,179)
SWEPCo
Trading Assets
Electricity
Physicals $ 9,329 $ 54,647
Trading Liabilities
Electricity
Physicals $ (5,278) $ (51,747)
TCC
Trading Assets
Electricity
Physicals $ 26,752 $ 62,520
Trading Liabilities
Electricity
Physicals $ (21,136) $ (58,663)
Financials (202) -
TNC
Trading Assets
Electricity
Physicals $ 6,323 $ 18,567
Trading Liabilities
Electricity
Physicals $ (4,047) $ (17,652)
Financials (233) -
Credit Risk
AEP limits credit risk by extending unsecured credit to entities based on
internal ratings. AEP uses Moody's Investor Service, Standard and Poor's and
qualitative and quantitative data to independently assess the financial health
of counterparties on an ongoing basis. This data, in conjunction with the
ratings information, is used to determine appropriate risk parameters. AEP also
requires cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.
We trade electricity and gas contracts with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty are not material to our financial
condition at December 31, 2002. At December 31, 2002, less than 7% of our
exposure was below investment grade as expressed in terms of Net Mark to Market
Assets. Net Mark to Market Assets represents the aggregate difference between
the forward market price for the remaining term of the contract and the
contractual price per counterparty. The following table approximates
counterparty credit quality and exposure for AEP based on netting across AEP
entities, commodities and instruments at December 31, 2002:
Futures,
Forward and
Counterparty Swap
Credit Quality Contracts Options Total
----------- ------- -----
(in millions)
AAA/Exchanges $ 26 $ 2 $ 28
AA 307 33 340
A 448 26 474
BBB 700 101 801
Below Investment
Grade 107 11 118
------- ------ ------
Total $1,588 $ 173 $1,761
====== ===== ======
We enter into transactions for electricity and natural gas as part of wholesale
trading operations. Electricity and gas transactions are executed
over-the-counter with counterparties or through brokers. Gas transactions are
also executed through brokerage accounts with brokers who are registered with
the U.S. Commodity Futures Trading Commission. Brokers and counterparties
require cash or cash-related instruments to be deposited on these transactions
as margin against open positions. The combined margin deposits at December 31,
2002 and 2001 were $109 million and $55 million. These margin accounts are
restricted and therefore are not included in Cash and Cash Equivalents on the
Consolidated Balance Sheets. AEP and its subsidiaries can be subject to further
margin requirements should related commodity prices change.
The margin deposits at December 31, 2002 for the registrants were:
(in thousands)
APCo $1,010
CSPCo 673
I&M 727
KPCo 261
OPCo 1,400
PSO 91
SWEPCo 105
TCC 121
TNC 37
Financial Derivatives and Hedging
In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. AEP recorded a favorable
transition adjustment to Accumulated Other Comprehensive Income of $27 million
at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives
included in the transition adjustment are interest rate swaps, foreign currency
swaps and commodity swaps, options and futures.
Most of the derivatives identified in the trans-ition adjustment were designated
as cash flow hedges and relate to foreign operations.
Certain derivatives may be designated for accounting purposes as a hedge of
either the fair value of an asset, liability, firm commitment, or a hedge of the
variability of cash flows related to a variable-priced asset, liability,
commitment, or forecasted trans-action. To qualify for hedge accounting, the
relationship between the hedging instrument and the hedged item must be
documented to include the risk management objective and strategy for use of the
hedge instrument. At the inception of the hedge and on an ongoing basis, the
effectiveness of the hedge is assessed to determine whether the hedge will be or
is highly effective in offsetting changes in fair value or cash flows of the
item being hedged. Changes in the fair value that result from the
ineffectiveness of a hedge under SFAS 133 are recognized currently in earnings
through mark-to-market accounting. Changes in the fair value of effective cash
flow hedges are reported in Accumulated Other Comprehensive Income. Gains and
losses from cash flow hedges in other comprehensive income are reclassified to
earnings in the accounting periods in which the variability of cash flows of the
hedged items affect earnings
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on
AEP's Consolidated Balance Sheets at December 31, 2002 are:
Accumulated
Other Comprehensive
Hedging Assets Hedging Liabilities Income (Loss) After Tax
-------------- ------------------- -----------------------
(in millions)
lectricity and Gas $6 $ (8) $ (2)
nterest Rate - (13)* (12)
oreign Currency - (2) (2)
----
$(16)
* Includes $6 million loss recorded in an equity investment.
The following table represents the activity in Other Comprehensive Income (Loss)
related to the effect of adopting SFAS 133 for derivative contracts that qualify
as cash flow hedges at December 31, 2002:
(in millions)
AEP Consolidated
Beginning Balance, January 1, 2002 $ (3)
Changes in fair value (56)
Reclasses from OCI to net loss 43
-------
Accumulated OCI derivative loss, December 31, 2002 $ (16)
=======
(in thousands)
APCo
Beginning Balance, January 1, 2002 $ (340)
Effective portion of changes in fair value (1,310)
Reclasses from OCI to net income (270)
-------
Accumulated OCI derivative loss, December 31, 2002 $(1,920)
=======
CSPCo
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 62
Reclasses from OCI to net income (329)
-------
Accumulated OCI derivative Loss, December 31, 2002 $ (267)
=======
I&M
Beginning Balance, January 1, 2002 $(3,835)
Effective portion of changes in fair value 34
Reclasses from OCI to net income 3,515
-------
Accumulated OCI derivative loss, December 31, 2002 $ (286)
=======
KPCo
Beginning Balance, January 1, 2002 $(1,903)
Effective portion of changes in fair value 343
Reclasses from OCI to net income 1,882
-------
Accumulated OCI derivative gain, December 31, 2002 $ 322
=======
OPCo
Beginning Balance, January 1, 2002 $ (196)
Effective portion of changes in fair value (103)
Reclasses from OCI to net income (439)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (738)
=======
PSO
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 2
Reclasses from OCI to net income (44)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (42)
=======
SWEPCo
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 1
Reclasses from OCI to net income (49)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (48)
=======
TCC
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 30
Reclasses from OCI to net income (66)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (36)
=======
TNC
Beginning Balance, January 1, 2002 $ -
Effective portion of changes in fair value 3
Reclasses from OCI to net income (18)
-------
Accumulated OCI derivative loss, December 31, 2002 $ (15)
=======
Approximately $9 million of net losses from cash flow hedges in Accumulated
Other Comprehensive Income (Loss) at December 31, 2002 are expected to be
reclassified to net income in the next twelve months as the items being hedged
settle. The actual amounts reclassified from Accumulated Other Comprehensive
Income to Net Income can differ as a result of market price changes. The maximum
term for which the exposure to the variability of future cash flows is being
hedged is five years.
Financial Instruments
Market Valuation of Non-Derivative Financial Instrument
The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term
Debt and Accounts Payable approximate fair value because of the short-term
maturity of these instruments. The book value of the pre-April 1983 spent
nuclear fuel disposal liability approximates the best estimate of its fair
value.
The fair values of Long-term Debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange. The book values and fair values of significant financial
instruments for AEP and its registrant subsidiaries at December 31, 2002 and
2001 are summarized in the following tables.
2002 2001
---- ----
Book Value Fair Value Book Value Fair Value
---------- ---------- ---------- ----------
(in millions) (in millions)
AEP
Long-term Debt $ 10,125 $ 10,470 $ 9,505 $ 9,542
Preferred Stock 84 77 95 93
Trust Preferred Securities 321 324 321 321
(in thousands) (in thousands)
AEGCo
Long-term Debt $ 44,802 $ 48,103 $ 44,793 $ 45,268
APCo
Long-term Debt $1,893,861 $1,953,087 $1,556,559 $1,439,531
Preferred Stock 10,860 9,774 10,860 10,860
CSPCo
Long-term Debt $ 621,626 $ 643,715 $ 791,848 $ 802,194
Preferred Stock - - 10,000 10,100
I&M
Long-term Debt $1,617,062 $1,673,363 $1,652,082 $1,672,392
Preferred Stock 64,945 58,948 64,945 62,795
KPCo
Long-term Debt $ 466,632 $ 475,455 $ 346,093 $ 350,233
OPCo
Long-term Debt $1,067,314 $1,095,197 $1,203,841 $1,227,880
Preferred Stock 8,850 7,965 8,850 8,837
PSO
Long-term Debt $ 545,437 $ 570,761 $ 451,129 $ 462,903
Trust Preferred Securities 75,000 75,900 75,000 74,730
SWEPCo
Long-term Debt $ 693,448 $ 727,085 $ 645,283 $ 656,998
Trust Preferred Securities 110,000 110,880 110,000 109,780
TCC
Long-term Debt $1,438,565 $1,522,373 $1,253,768 $1,278,644
Trust Preferred Securities 136,250 136,959 136,250 135,760
TNC
Long-term Debt $ 132,500 $ 144,060 $ 255,967 $ 266,846
Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The
trust investments which are classified as held for sale for decommissioning and
SNF disposal, reported in Other Assets on AEP's Consolidated Balance Sheets, are
recorded at market value in accordance with SFAS 115 "Accounting for Certain
Investments in Debt and Equity Securities". At December 31, 2002 and 2001, the
fair values of the trust investments were $969 million and $933 million,
respectively, and had a cost basis of $909 million and $839 million,
respectively. The change in market value in 2002, 2001, and 2000 was a net
unrealized holding loss of $33 million and $11 million and a net unrealized
holding gain of $6 million, respectively.
18. Income Taxes:
The details of AEP's consolidated income taxes before discontinued operations,
extraordinary items, and cumulative effect as reported are as follows:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Federal:
Current $ 330 $404 $ 793
Deferred (192) 60 (236)
----- ---- -----
Total 138 464 557
----- ---- -----
State:
Current 32 61 47
Deferred 30 34 (6)
----- ---- -----
Total 62 95 41
----- ---- -----
International:
Current 13 (13) 4
Deferred 1 - -
----- ---- ------
Total 14 (13) 4
----- ---- -----
Total Income Tax
as Reported
Before
Discontinued
Operations,
Extraordinary
Items and
Cumulative
Effect $ 214 $546 $ 602
===== ==== =====
The details of the registrant subsidiaries income taxes as reported are as
follows:
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2002 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 6,607 $ 99,140 $ 81,539 $ 66,063 $ 680
Deferred (5,028) 17,626 25,771 (19,870) 9,451
Deferred Investment Tax Credits 2 (3,229) (3,096) (7,340) (1,173)
-------- -------- -------- --------- -------
Total 1,581 113,537 104,214 38,853 8,958
-------- -------- -------- --------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (173) (354) 9,442 3,435 1,583
Deferred - (849) (2,479) 2,949 388
Deferred Investment Tax Credits (3,363) (1,408) (174) (400) (67)
-------- -------- -------- --------- --------
Total (3,536) (2,611) 6,789 5,984 1,904
-------- -------- -------- --------- --------
Total Income Tax as Reported $ (1,955) $110,926 $111,003 $ 44,837 $ 10,862
======== ======== ======== ========= ========
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2002 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 86,026 $(49,673) $ 41,354 $ 30,495 $ 109
Deferred 30,048 75,659 (3,134) 113,726 (10,652)
Deferred Investment Tax Credits (2,493) (1,791) (4,524) (5,207) (1,271)
-------- -------- -------- --------- --------
Total 113,581 24,195 33,696 139,014 (11,814)
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current 2,732 (1,812) 1,772 3,223 1,334
Deferred 15,962 - - (71) (1,623)
Deferred Investment Tax Credits (684) - - - -
-------- -------- -------- --------- --------
Total 18,010 (1,812) 1,772 3,152 (289)
-------- -------- -------- --------- --------
Total Income Tax as Reported $131,591 $ 22,383 $ 35,468 $ 142,166 $(12,103)
======== ======== ======== ========= ========
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2001 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 9,126 $ 71,623 $ 88,013 $ 107,286 $ 7,726
Deferred (6,224) 27,198 14,923 (45,785) 2,812
Deferred Investment Tax Credits - (3,237) (3,899) (7,377) (1,180)
-------- -------- -------- --------- --------
Total 2,902 95,584 99,037 54,124 9,358
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (56) (19,165) (13,803) (10,590) (2,725)
Deferred - 21,832 17,885 16,580 3,481
Deferred Investment Tax Credits (3,414) (1,528) (159) (947) (72)
-------- -------- -------- --------- --------
Total (3,470) 1,139 3,923 5,043 684
-------- -------- -------- --------- --------
Total Income Tax as Reported $ (568) $ 96,723 $102,960 $ 59,167 $ 10,042
======== ======== ======== ========= ========
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2001 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $(62,298) $ 53,030 $ 77,965 $ 190,671 $ 19,424
Deferred 166,166 (16,726) (31,396) (72,568) (11,891)
Deferred Investment Tax Credits (2,495) (1,791) (4,453) (5,207) (1,271)
-------- -------- -------- --------- --------
Total 101,373 34,513 42,116 112,896 6,262
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (21,600) 352 542 (398) (691)
Deferred 20,014 - - - -
Deferred Investment Tax Credits (794) - - - -
-------- -------- -------- --------- --------
Total (2,380) 352 542 (398) (691)
-------- -------- -------- --------- --------
Total Income Tax as Reported $ 98,993 $ 34,865 $ 42,658 $ 112,498 $ 5,571
======== ======== ======== ========= ========
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 8,746 $129,165 $120,494 $ 134,796 $ 17,878
Deferred (5,842) 3,838 (7,746) (126,748) 2,521
Deferred Investment Tax Credits - (2,947) (3,379) (7,524) (1,187)
-------- -------- -------- --------- --------
Total 2,904 130,056 109,369 524 19,212
-------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (44) 327 3,777 2,950 (50)
Deferred - 4,764 3,683 1,569 1,244
Deferred Investment Tax Credits (3,396) (1,968) (103) (330) (65)
-------- -------- -------- --------- --------
Total (3,440) 3,123 7,357 4,189 1,129
-------- -------- -------- --------- --------
Total Income Tax as Reported $ (536) $133,179 $116,726 $ 4,713 $ 20,341
======== ======== ======== ========= ========
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 259,608 $ 11,597 $ 16,073 $ 89,403 $ 6,774
Deferred (70,263) 25,453 14,653 16,263 9,401
Deferred Investment Tax Credits (1,824) (1,791) (4,482) (5,207) (1,271)
--------- -------- -------- --------- --------
Total 187,521 35,259 26,244 100,459 14,904
--------- -------- -------- --------- --------
Charged (Credited) to
Nonoperating Income (net):
Current 15,426 (1,306) (1,476) (5,073) (222)
Deferred 4,307 - - - (1,237)
Deferred Investment Tax Credits ( 1,575) - - - -
--------- -------- -------- --------- ---------
Total 18,158 (1,306) (1,476) (5,073) (1,459)
--------- -------- -------- --------- --------
Total Income Tax as Reported $ 205,679 $ 33,953 $24,768 $ 95,386 $ 13,445
========= ======== ======= ========= ========
The following is a reconciliation for AEP Consolidated of the difference between
the amount of federal income taxes computed by multiplying book income before
federal income taxes by the statutory tax rate, and the amount of income taxes
reported.
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
Net Income (Loss) $(519) $ 971 $267
Discontinued Operations (net of income tax
Of $73 million in 2002, $22 million in 2001
and $5 million in 2000) 190 (86) (122)
Extraordinary Items
(net of income tax of $20 million in 2001
and $44 million in 2000) - 50 35
Cumulative Effect of Accounting Change
(net of income tax of $2 million in 2001) 350 (18) -
Preferred Stock Dividends 11 10 11
----- ------ ----
Income Before Preferred Stock Dividends
of Subsidiaries 32 927 191
Income Taxes Before Discontinued Operations,
Extraordinary Items and Cumulative Effect 214 546 602
----- ------ ----
Pre-Tax Income $ 246 $1,473 $793
===== ====== ====
Income Taxes on Pre-Tax Income
at Statutory Rate (35%) $ 86 $ 516 $278
Increase (Decrease) in Income Taxes
Resulting from the Following Items:
Depreciation 32 48 77
Corporate Owned Life Insurance - 4 247
Investment Tax Credits (net) (35) (37) (36)
Tax Effects of International Operations 123 (12) (1)
Energy Production Credits (14) - -
Merger Transaction Costs - - 49
State Income Taxes 40 62 26
Other (18) (35) (38)
----- ------ ----
Total Income Taxes as Reported Before
Discontinued Operations, Extraordinary
Items and Cumulative Effect $ 214 $ 546 $602
===== ====== ====
Effective Income Tax Rate 87.0% 37.1% 75.9%
===== ====== ====
Shown below is a reconciliation for each AEP registrant subsidiary of the
difference between the amount of federal income taxes computed by multiplying
book income before federal income taxes by the statutory rate, and the amount of
income taxes reported.
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2002 (in thousands)
Net Income $ 7,552 $205,492 $181,173 $ 73,992 $ 20,567
Income Taxes (1,955) 110,926 111,003 44,837 10,862
-------- -------- -------- -------- --------
Pre-Tax Income $ 5,597 $316,418 $292,176 $118,829 $ 31,429
======== ======== ======== ======== ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 1,959 $110,746 $102,262 $ 41,590 $ 11,000
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 870 3,082 2,899 21,812 2,057
Corporate Owned Life Insurance - (93) 719 268 305
Nuclear Fuel Disposal Costs - - - (3,814) -
Allowance for Funds Used
During Construction (446) - - (3,453) -
Rockport Plant Unit 2 Investment
Tax Credit (748) - - - -
Removal Costs - - - - (735)
Investment Tax Credits (net) (3,361) (4,637) (3,270) (7,740) (1,240)
State Income Taxes 335 6,469 11,387 124 1,058
Other (564) (4,641) (2,994) (3,950) (1,583)
-------- -------- -------- -------- --------
Total Income Taxes as Reported $ (1,955) $110,926 $111,003 $ 44,837 $ 10,862
======== ======== ======== ======== ========
Effective Income Tax Rate N.M. 35.1% 38.0% 37.7% 34.6%
==== ===== ===== ===== =====
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2002 (in thousands)
Net Income (Loss) $220,023 $ 41,060 $ 82,992 $ 275,941 $(13,677)
Income Taxes 131,591 22,383 35,468 142,166 (12,103)
-------- -------- -------- --------- --------
Pre-Tax Income (Loss) $351,614 $ 63,443 $118,460 $ 418,107 $(25,780)
======== ======== ======== ========= ========
Income Tax on Pre-Tax Income (Loss)
at Statutory Rate (35%) $123,065 $ 22,205 $ 41,461 $ 146,337 $ (9,023)
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 4,227 (583) (2,790) (295) (32)
Corporate Owned Life Insurance (84) - - - -
Investment Tax Credits (net) (3,177) (1,791) (4,524) (5,207) (1,271)
State Income Taxes 18,051 2,639 3,987 2,202 (1,577)
Other (10,491) (87) (2,666) (871) (200)
-------- -------- -------- --------- --------
Total Income Taxes as Reported $131,591 $ 22,383 $ 35,468 $ 142,166 $(12,103)
======== ======== ======== ========= ========
Effective Income Tax Rate 37.4% 35.3% 29.9% 34.0% 47.0%
===== ===== ===== ===== =====
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2001 (in thousands)
Net Income $ 7,875 $161,818 $161,876 $ 75,788 $ 21,565
Extraordinary Loss - - 30,024 - -
Income Taxes (568) 96,723 102,960 59,167 10,042
------- -------- -------- --------- --------
Pre-Tax Income $ 7,307 $258,541 $294,860 $ 134,955 $ 31,607
======= ======== ======== ========= ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 2,557 $ 90,489 $103,201 $ 47,234 $ 11,062
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 230 2,977 2,757 21,224 1,581
Corporate Owned Life Insurance - 450 544 (148) 334
Nuclear Fuel Disposal Costs - - - (3,292) -
Allowance for Funds Used
During Construction (1,078) - - (1,606) -
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - - - - (420)
Investment Tax Credits (net) (3,414) (4,765) (4,058) (8,324) (1,252)
State Income Taxes 1,050 9,613 5,727 6,137 318
Other (287) (2,041) (5,211) (2,058) (1,581)
-------- -------- -------- --------- --------
Total Income Taxes as Reported $ (568) $ 96,723 $102,960 $ 59,167 $ 10,042
======== ======== ======== ========= ========
Effective Income Tax Rate N.M. 37.4% 34.9% 43.8% 31.8%
==== ===== ===== ===== =====
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2001 (in thousands)
Net Income $ 147,445 $ 57,759 $ 89,367 $ 182,278 $ 12,310
Extraordinary Loss 18,348 - - 2,509 -
Income Taxes 98,993 34,865 42,658 112,498 5,571
--------- -------- -------- --------- --------
Pre-Tax Income $ 264,786 $ 92,624 $132,025 $ 297,285 $ 17,881
========= ======== ======== ========= ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 92,675 $ 32,418 $ 46,209 $ 104,050 $ 6,258
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 7,972 1,127 (501) 8,477 1,463
Corporate Owned Life Insurance 1,852 - - - -
Investment Tax Credits (net) (3,289) (1,791) (4,453) (5,207) (1,271)
State Income Taxes 9,752 5,137 5,451 9,652 1,283
Other (9,969) (2,026) (4,048) (4,474) (2,162)
--------- -------- -------- --------- --------
Total Income Taxes as Reported $ 98,993 $ 34,865 $ 42,658 $ 112,498 $ 5,571
========= ======== ======== ========= ========
Effective Income Tax Rate 37.4% 37.6% 32.3% 37.8% 31.2%
==== ==== ==== ===== =====
AEGCo APCo CSPCo I&M KPCo
Year Ended December 31, 2000 (in thousands)
Net Income (Loss) $ 7,984 $ 73,844 $ 94,966 $(132,032) $ 20,763
Extraordinary (Gains) Loss (1,066) 39,384 - -
Income Tax Benefit - (7,872) (14,148) - -
Income Taxes (536) 133,179 116,726 4,713 20,341
------- -------- -------- --------- --------
Pre-Tax Income (Loss) $ 7,448 $198,085 $236,928 $(127,319) $ 41,104
======= ======== ======== ========= ========
Income Tax on Pre-Tax Income
(Loss) at Statutory Rate (35%) $ 2,607 $ 69,330 $ 82,925 $ (44,562) $ 14,386
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 452 7,606 10,529 20,378 1,827
Corporate Owned Life Insurance - 54,824 29,259 42,587 5,149
Nuclear Fuel Disposal Costs - - - (3,957) -
Allowance for Funds Used
During Construction (1,070) - - (2,211) -
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - (1,197) - - (420)
Investment Tax Credits (net) (3,396) (4,915) (3,482) (7,854) (1,252)
State Income Taxes 784 9,950 89 6,004 1,597
Other (287) (2,419) (2,594) (5,672) (946)
-------- -------- -------- --------- --------
Total Income Taxes as Reported $ (536) $133,179 $116,726 $ 4,713 $ 20,341
======== ======== ======== ========= ========
Effective Income Tax Rate N.M. 67.2% 49.3% N.M. 49.5%
==== ==== ==== ==== =====
OPCo PSO SWEPCo TCC TNC
Year Ended December 31, 2000 (in thousands)
Net Income $ 83,737 $ 66,663 $ 72,672 $ 189,567 $ 27,450
Extraordinary Loss 40,157 - - - -
Income Tax Benefit (21,281) - - - -
Income Taxes 205,679 33,953 24,768 95,386 13,445
--------- -------- -------- --------- --------
Pre-Tax Income $ 308,292 $100,616 $ 97,440 $ 284,953 $ 40,895
========= ======== ======== ========= ========
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $ 107,902 $ 35,216 $ 34,104 $ 99,734 $ 14,313
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 27,577 695 (1,012) 7,556 1,204
Corporate Owned Life Insurance 84,453 - - - -
Investment Tax Credits (net) (3,398) (1,791) (4,482) (5,207) (1,271)
State Income Taxes (1,988) 3,037 1,650 2,296 -
Other (8,867) (3,204) (5,492) (8,993) (801)
--------- -------- -------- --------- --------
Total Income Taxes as Reported $ 205,679 $ 33,953 $ 24,768 $ 95,386 $ 13,445
========= ======== ======== ========= ========
Effective Income Tax Rate 66.7% 33.7% 25.4% 33.5% 32.9%
==== ==== ==== ===== ====
The following tables show the elements of the net deferred tax liability and the
significant temporary differences for AEP Consolidated and each registrant
subsidiary:
December 31, 2002 2001
- -------------- ---- ----
(in millions)
Deferred Tax Assets $ 2,189 $ 1,216
Deferred Tax Liabilities (6,105) (5,716)
------- -------
Net Deferred Tax Liabilities $(3,916) $(4,500)
======= =======
Property Related Temporary Differences $(3,612) $(3,674)
Amounts Due From Customers For Future
Federal Income Taxes (360) (245)
Deferred State Income Taxes (422) (314)
Transition Regulatory Assets (234) (268)
Regulatory Assets Designated for Securitization (310) (332)
Asset Impairments and Investment Value Losses 417 -
Deferred Income Taxes on Other Comprehensive Loss 326 3
All Other (net) 279 330
------- -------
Net Deferred Tax Liabilities $(3,916) $(4,500)
======= =======
AEGCo APCo CSPCo I&M KPCo
December 31, 2002 (in thousands)
Deferred Tax Assets $ 73,094 $ 213,972 $ 72,990 $ 348,672 $ 36,948
Deferred Tax Liabilities (102,096) (915,773) (510,761) (704,869) (215,261)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $ (29,002) $(701,801) $(437,771) $(356,197) $(178,313)
========== ========= ========= ========= =========
Property Related Temporary Differences $ (74,291) $(555,824) $(331,381) $(343,587) $(127,073)
Amounts Due From Customers For
Future Federal Income Taxes 7,626 (58,246) (8,895) (38,752) (20,488)
Deferred State Income Taxes (5,119) (77,693) (23,448) (52,528) (28,722)
Transition Regulatory Assets - (28,735) (71,752) - -
Asset Impairments and Investment
Value Losses - 18 215 225 4
Deferred Income Taxes on Other
Comprehensive Loss - 38,823 31,961 21,800 5,089
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 38,866 - - 25,860 -
Accrued Nuclear Decommissioning Expense - - - 65,856 -
Deferred Fuel and Purchased Power - (1,878) (273) (13,144) 415
Deferred Cook Plant Restart Costs - - - (14,000) -
Nuclear Fuel - - - (5,153) -
All Other (net) 3,916 (18,266) (34,198) (2,774) (7,538)
--------- -------- --------- --------- ---------
Net Deferred Tax Liabilities $ (29,002) $(701,801) $(437,771) $(356,197) $(178,313)
========= ========= ========= ========= =========
OPCo PSO SWEPCo TCC TNC
December 31, 2002 (in thousands)
Deferred Tax Assets $ 155,334 $ 70,649 $ 82,113 $ 130,210 $ 35,970
Deferred Tax Liabilities (949,721) (412,045) (423,177) (1,391,462) (153,491)
--------- --------- --------- ----------- ---------
Net Deferred Tax Liabilities $(794,387) $(341,396) $(341,064) $(1,261,252) $(117,521)
========= ========= ========= =========== =========
Property Related Temporary Differences $(620,634) $(303,888) $(315,821) $ (709,246) $(142,034)
Amounts Due From Customers For
Future Federal Income Taxes (53,256) 9,490 (4,078) (198,595) 5,726
Deferred State Income Taxes (46,990) (57,911) (48,372) (66,333) (4,080)
Transition Regulatory Assets (131,833) - - - -
Asset Impairments and Investment
Value Losses 615 - - - 14,996
Deferred Income Taxes on Other
Comprehensive Loss 39,246 29,332 28,906 39,394 16,565
Deferred Fuel and Purchased Power 540 (28,696) 3,192 2,655 (9,933)
Regulatory Assets Designated
For Securitization - - - (310,410) -
All Other (net) 17,925 10,277 (4,891) (18,717) 1,239
--------- --------- --------- ----------- ---------
Net Deferred Tax Liabilities $(794,387) $(341,396) $(341,064) $(1,261,252) $(117,521)
========= ========= ========= =========== =========
AEGCo APCo CSPCo I&M KPCo
December 31, 2001 (in thousands)
Deferred Tax Assets $ 75,856 $ 162,334 $ 74,767 $ 332,225 $ 30,927
Deferred Tax Liabilities (103,831) (865,909) (518,489) (732,756) (199,231)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $ (27,975) $(703,575) $(443,722) $(400,531) $(168,304)
========= ========= ========= ========= =========
Property Related Temporary Differences $ (70,581) $(530,298) $(323,139) $(306,151) $(118,147)
Amounts Due From Customers For
Future Federal Income Taxes 9,292 (55,206) (9,839) (46,756) (20,215)
Deferred State Income Taxes (3,822) (56,747) (8,968) (38,015) (25,267)
Transition Regulatory Assets - (34,783) (78,298) - -
Deferred Income Taxes on Other
Comprehensive Loss - 183 - 2,065 1,025
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 40,816 - - 27,157 -
Accrued Nuclear Decommissioning Expense - - - 43,707 -
Deferred Fuel and Purchased Power - (4,106) (39) (26,270) 57
Deferred Cook Plant Restart Costs - - - (28,000) -
Nuclear Fuel - - - (16,062) -
All Other (net) (3,680) (22,618) (23,439) (12,206) (5,757)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $ (27,975) $(703,575) $(443,722) $(400,531) $(168,304)
========= ========= ========= ========= =========
OPCo PSO SWEPCo TCC TNC
December 31, 2001 (in thousands)
Deferred Tax Assets $ 135,938 $ 59,421 $ 56,189 $ 130,863 $ 22,888
Deferred Tax Liabilities (933,827) 356,298) (425,970) (1,294,658) (167,937)
--------- -------- --------- ----------- ---------
Net Deferred Tax Liabilities $(797,889) $(296,877) $(369,781) $(1,163,795) $(145,049)
========= ========= ========= =========== =========
Property Related Temporary
Differences $(595,974) $(320,900) $(362,884) $ (808,922) $(149,309)
Amounts Due From Customers For
Future Federal Income Taxes (61,130) 10,199 (6,441) (70,174) 4,757
Deferred State Income Taxes (18,440) (35,038) (48,729) (66,333) (4,079)
Transition Regulatory Assets (154,947) - - - -
Deferred Income Taxes on Other
Comprehensive Loss 106 - - - -
Deferred Fuel and Purchased Power 12 3,052 (2,778) 18,032 (11,756)
Provision for Mine Shutdown Costs 20,323 - - - -
Regulatory Assets Designated
For Securitization - - - (332,198) -
All Other (net) 12,161 45,810 51,051 95,800 15,338
--------- --------- -------- ------------ ---------
Net Deferred Tax Liabilities $(797,889) $(296,877) $(369,781) $(1,163,795) $(145,049)
========= ========= ========= =========== =========
We have settled with the IRS all issues from the audits of our consolidated
federal income tax returns for the years prior to 1991. We have received Revenue
Agent's Reports from the IRS for the years 1991 through 1996, and have filed
protests contesting certain proposed adjustments. Returns for the years 1997
through 2000 are presently being audited by the IRS. Management is not aware of
any issues for open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.
COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern
District of Ohio ruled against AEP in its suit against the United States over
deductibility of interest claimed by AEP in its consolidated federal income tax
returns related to its COLI program. AEP had filed suit to resolve the IRS'
assertion that interest deductions for AEP's COLI program should not be allowed.
In 1998 and 1999 the Company paid the disputed taxes and interest attributable
to COLI interest deductions for taxable years 1991-98 to avoid the potential
assessment by the IRS of additional interest on the contested tax. The payments
were included in other assets pending the resolution of this matter. As a result
of the U.S. District Court's decision to deny the COLI interest deductions, net
income was reduced by $319 million in 2000. The Company has filed an appeal of
the U.S. District Court's decision with the U.S. Court of Appeals for the 6th
Circuit.
The earnings reductions recorded in 2000 for affected registrant subsidiaries
were as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
The Company joins in the filing of a consolidated federal income tax return with
its affiliated companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is in accordance
with SEC rules under the 1935 Act. These rules permit the allocation of the
benefit of current tax losses to the System companies giving rise to them in
determing their current tax expense. The tax loss of the System parent company,
AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the
exception of the loss of the parent company, the method of allocation
approximates a separate return result for each company in the consolidated
group.
19. Basic and Diluted Earnings Per Share:
The calculation of AEP's basic and diluted earnings (loss) per common share
(EPS) is based on the amounts of Net Income (Loss) and weighted average common
shares shown in the table below:
2002 2001 2000
---- ---- ----
(in millions - except
per share amounts)
Income:
Income Before Discontinued
Operations, Extraordinary
Items and Cumulative
Effect $ 21 $ 917 $ 180
Discontinued Operations (190) 86 122
------ ----- -----
Income (Loss) Before
Extraordinary Item
And Cumulative Effect (169) 1,003 302
Extraordinary Losses
(net of tax):
Discontinuance of
Regulatory Accounting
For Generation - (48) (35)
Loss on Reacquired Debt - (2) -
Cumulative Effect of
Accounting Change
(net of tax) (350) 18 -
----- ----- -----
Net Income (Loss) $(519) $ 971 $ 267
===== ====== =====
Weighted Average Shares:
Average Common
Shares Outstanding 332 322 322
Assumed Conversion of
Dilutive Stock Options
(see Note 15) - 1 -
----- ----- -----
Diluted Average Common
Shares Outstanding 332 323 322
===== ===== =====
Basic and Diluted
Earnings Per Common Share:
Income Before Discontinued
Operations, Extraordinary
Items and Cumulative
Effect $ 0.06 $2.85 $0.56
Discontinued Operations (0.57) 0.26 0.38
------ ----- -----
Income (Loss) Before
Extraordinary Item and
Cumulative Effect (0.51) 3.11 0.94
Extraordinary Losses
(net of tax):
Discontinuance of
Regulatory Accounting
For Generation - (0.15) (0.11)
Loss on Reacquired Debt - (0.01) -
Cumulative Effect
of Accounting Change
(net of tax) (1.06) 0.06 -
------ ----- -----
$(1.57) $3.01 $0.83
====== ===== =====
The assumed conversion of stock options does not affect net earnings (loss) for
purposes of calculating diluted earnings per share. AEP's basic and diluted EPS
are the same in 2002, 2001 and 2000 since the effect on weighted average common
shares outstanding is minimal.
Had AEP recognized net income in fiscal 2002, incremental shares attributable to
the assumed exercise of outstanding stock options would have increased diluted
common shares outstanding by 398,000 shares.
Options to purchase 8.8 million, 0.7 million and 6.4 million shares of common
stock were outstanding at December 31, 2002, 2001 and 2000, respectively, but
were not included in the computation of diluted earnings per share because the
options' exercise prices were greater than the year-end market price of the
common shares and, therefore, the effect would be antidilutive.
In addition, there is no effect on diluted earnings per share related to our
equity units (issued in 2002) unless the market value of AEP common stock
exceeds $49.08 per share. There were no dilutive effects from equity units at
December 31, 2002. If our common stock value exceeds $49.08 we would apply the
treasury stock method to the equity units to calculate diluted earnings per
share. This method of calculation theoretically assumes that the proceeds
received as a result of the forward purchase contracts are used to repurchase
outstanding shares. Also see Note 27.
20. Supplementary Information:
Year Ended December 31,
-----------------------
2002 2001 2000
---- ---- ----
(in millions)
AEP Consolidated Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $142 $127 $86
Cash was paid for:
Interest (net of capitalized amounts) $792 $972 $842
Income Taxes $336 $569 $449
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $ 6 $17 $118
Assumption of Liabilities Related to Acquisitions $1 $171 -
Exchange of Communication Investment for Common Stock - $5 -
The amounts of power purchased by the registrant subsidiaries from Ohio Valley
Electric Corporation, which is 44.2% owned by the AEP System, for the years
ended December 31, 2002, 2001, and 2000 were:
APCo CSPCo I&M OPCo
---- ----- --- ----
(in thousands)
Year Ended December 31, 2002 $53,386 $14,885 $23,282 $50,135
Year Ended December 31, 2001 45,542 12,626 20,723 47,757
Year Ended December 31, 2000 30,998 8,706 15,204 31,134
21. Power and Distribution Projects:
Power Projects
AEP owns interests of 50% or less in domestic unregulated power plants with a
capacity of 1,483 MW located in Colorado, Florida and Texas. In addition to the
domestic projects, AEP has equity interests in international power plants
totaling 1,113 MW.
Investments in power projects that are 50% or less owned are accounted for by
the equity method and reported in Investments in Power and Distribution Projects
on AEP's Consolidated Balance Sheets (see "Eastex" within the Assets Held for
Sale section of Note 13), except for Eastex Cogeneration which, due to its
structure, is consolidated. At December 31, 2002, six domestic power projects
and three international power investments are accounted for under the equity
method. The six domestic projects are combined cycle gas turbines that provide
steam to a host commercial customer and are considered either Qualifying
Facilities (QFs) or Exempt Wholesale Generators (EWGs) under PURPA. The three
international power investments are classified as Foreign Utility Companies
(FUCO) under the Energy Policies Act of 1992. Two of the international
investments are power projects and the other international investment is a
company which owns an interest in four additional power projects. All of the
power projects accounted for under the equity method have unrelated third-party
partners.
Seven of the above power projects have project-level financing, which is
non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $58 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits.
Distribution Projects
AEP owns a 44% equity interest in Vale, a Brazilian electric operating company
which was purchased for a total of $149 million. On December 1, 2001 AEP
converted a $66 million note receivable and accrued interest into a 20% equity
interest in Caiua (Brazilian electric operating company), a subsidiary of Vale.
Vale and Caiua have experienced losses from operations and AEP's investment has
been affected by the devaluation of the Brazilian Real. In December 2002, AEP
recorded an other than temporary impairment totaling $141.1 million (after
federal income tax benefit of $76 million) of its 44% equity investment in Vale
and its 20% equity interest in Caiua. See "Grupo Rede Investment" within the
Investment Values section of Note 13 "Asset Impairments and Investment Value
Losses", for further information on the 2002 impairment of AEP's Vale and Caiua
investments.
22. Leases:
Leases of property, plant and equipment are for periods up to 99 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment for regulated
operations. Capital leases for non-regulated property are accounted for as if
the assets were owned and financed. The components of rental costs are as
follows:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2002 (in thousands)
Lease Payments on
Operating Leases $346,000 $76,143 $ 6,634 $ 5,209 $110,833 $ 1,597 $68,816
Amortization of Capital Leases 65,000 238 9,729 6,010 8,319 2,171 12,637
Interest on Capital Leases 14,000 19 2,240 1,717 2,221 469 4,501
-------- ------- ------- ------- -------- ------- -------
Total Lease Rental Costs $425,000 $76,400 $18,603 $12,936 $121,373 $ 4,237 $85,954
======== ======= ======= ======= ======== ======= =======
PSO SWEPCo TCC TNC
Year Ended December 31, 2002 (in thousands)
Lease Payments on
Operating Leases $ 4,403 $3,240 $ 7,184 $ 1,981
Amortization of Capital Leases - - - -
Interest on Capital Leases - - - -
------- ------ ------- -------
Total Lease Rental Costs $ 4,403 $3,240 $ 7,184 $ 1,981
======= ====== ======= =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2001 (in thousands)
Lease Payments on
Operating Leases $293,000 $76,262 $ 6,142 $ 7,063 $104,574 $ 1,191 $63,913
Amortization of Capital Leases 82,000 281 12,099 7,206 17,933 2,740 14,443
Interest on Capital Leases 22,000 55 3,789 2,396 4,424 808 5,818
-------- ------- ------- ------- -------- ------- -------
Total Lease Rental Costs $397,000 $76,598 $22,030 $16,665 $126,931 $ 4,739 $84,174
======== ======= ======= ======= ======== ======= =======
PSO SWEPCo TCC TNC
Year Ended December 31, 2001 (in thousands)
Lease Payments on
Operating Leases $ 4,010 $ 2,277 $ 5,948 $ 1,534
Amortization of Capital Leases - - - -
Interest on Capital Leases - - - -
-------- ------- ------- -------
Total Lease Rental Costs $ 4,010 $ 2,277 $ 5,948 $ 1,534
======== ======= ======= =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $246,000 $73,858 $ 7,128 $ 7,683 $ 81,446 $ 1,978 $51,981
Amortization of Capital Leases 118,000 281 13,900 7,776 26,341 3,931 37,280
Interest on Capital Leases 36,000 55 3,930 2,690 10,908 1,054 9,584
-------- ------- ------- ------ -------- ------- -------
Total Lease Rental Costs $400,000 $74,194 $24,958 $18,149 $118,695 $ 6,963 $98,845
======== ======= ======= ======= ======== ======= =======
PSO SWEPCo TCC TNC
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $ 3,269 $ 1,401 $ 5,410 $ 1,210
Amortization of Capital Leases - - - -
Interest on Capital Leases - - - -
-------- ------- ------- -------
Total Lease Rental Costs $ 3,269 $ 1,401 $ 5,410 $ 1,210
======== ======= ======= =======
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
AEP AEGCO APCo CSPCo I&M KPCo
Year Ended December 31, 2002 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 40,000 $ 1,793 $ 3,368 $ 6,380 $ 5,728 $ 1,138
Distribution 15,000 - - - 14,589 -
Other:
Mining Assets and Other 687,000 - 67,395 46,791 70,140 14,258
-------- ------ ------- ------- -------- -------
Total Property, Plant
and Equipment 742,000 1,793 70,763 53,171 90,457 15,396
Accumulated Amortization 299,000 1,294 37,452 26,551 41,141 8,168
-------- ------- ------- ------- -------- ------
Net Property, Plant and
Equipment Under
Capital Leases $443,000 $ 499 $33,311 $26,620 $ 49,316 $ 7,228
======== ======= ======= ======= ======== =======
Obligations Under Capital Leases:
Noncurrent Liability $170,000 $ 301 $23,991 $21,643 $ 42,619 $ 5,093
Liability Due Within One Year 58,000 198 9,598 5,967 8,229 2,155
-------- ------- ------- ------- -------- ------
Total Obligations Under
Capital Leases $228,000 $ 499 $33,589 $27,610 $ 50,848 $ 7,248
======== ======= ======= ======= ======== =======
OPCo SWEPCo
Year Ended December 31, 2002 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 21,360 $ -
Distribution - -
Other:
Mining Assets and Other 103,018 45,699
Total Property, Plant
and Equipment 124,378 45,699
Accumulated Amortization 63,810 45,699
Net Property, Plant and
Equipment Under
Capital Leases $ 60,568 $ -
======== =======
Obligations Under Capital Leases:
Noncurrent Liability $ 51,266 $ -
Liability Due Within One Year 14,360 -
-------- -------
Total Obligations Under
Capital Leases $ 65,626 $ -
======== =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2001 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 39,000 $ 1,983 $ 2,712 $ 6,380 $ 4,826 $ 1,138 $ 22,477
Distribution 15,000 - - - 14,593 - -
Other:
Mining Assets and Other 723,000 129 82,292 54,999 86,267 17,658 114,944
-------- ------- ------- ------- --------- ------- -------
Total Property, Plant
and Equipment 777,000 2,112 85,004 61,379 105,686 18,796 137,421
Accumulated Amortization 250,000 1,801 38,745 26,044 43,768 9,213 57,429
-------- ------- ------- ------- --------- ------- --------
Net Property, Plant and
Equipment Under
Capital Leases $527,000 $ 311 $46,259 $35,335 $ 61,918 $ 9,583 $ 79,992
======== ======= ======= ======= ========= ======= ========
Obligations Under Capital Leases:
Noncurrent Liability $219,000 $ 76 $33,928 $27,052 $ 51,093 $ 6,742 $ 64,261
Liability Due Within One Year 75,000 235 12,357 7,835 10,840 2,841 16,405
-------- ------- ------- ------- --------- ------- --------
Total Obligations Under
Capital Leases $294,000 $ 311 $46,285 $34,887 $ 61,933 $ 9,583 $ 80,666
======== ======= ======= ======= ========= ======= ========
Future minimum lease payments consisted of the following at December 31, 2002:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Capital (in thousands)
- -------
2003 $ 70,000 $ 249 $12,483 $ 7,365 $ 10,373 $ 2,623 $ 17,363
2004 53,000 114 10,515 6,231 9,122 1,957 14,634
2005 37,000 58 6,799 5,279 6,506 1,581 11,442
2006 29,000 31 5,117 3,898 5,561 948 10,220
2007 21,000 29 2,668 2,969 4,024 788 8,694
Later Years 59,000 79 4,829 8,321 10,732 725 20,302
-------- ---------- ------- ------- --------- ------- --------
Total Future Minimum
Lease Payments 269,000 560 42,411 34,063 46,318 8,622 82,655
Less Estimated Interest Elemen 41,000 61 8,822 6,453 (4,530) 1,374 17,029
-------- ---------- ------- ------- --------- ------- --------
Estimated Present Value of
Future Minimum Lease
Payments $228,000 $ 499 $33,589 $27,610 $ 50,848 $ 7,248 $ 65,626
======== ========== ======= ======= ========= ======= ========
AEP AEGCo APCo CSPCo I&M KPCo OPCo
(in thousands)
Noncancellable Operating Leases
2003 $ 305,000 $ 73,854 $ 4,482 $ 4,608 $ 95,213 $ 1,031 $ 62,784
2004 271,000 73,854 3,723 5,111 81,246 865 62,837
2005 252,000 73,854 3,114 4,013 78,968 747 62,169
2006 242,000 73,854 2,742 1,630 77,741 576 62,481
2007 237,000 73,854 1,962 1,374 76,461 875 62,880
Later Years 2,462,000 1,107,810 4,384 2,670 1,117,725 1,492 180,548
---------- ---------- -------- ------- ---------- ------- --------
Total Future Minimum
Lease Payments $3,769,000 $1,477,080 $20,407 $19,406 $1,527,354 $ 5,586 $493,699
========== ========== ======= ======= ========== ======= ========
PSO SWEPCo TCC TNC
(in thousands)
Noncancellable Operating Leases
2003 $ 2,260 $ 912 $ 1,815 $ 448
2004 1,998 617 1,565 296
2005 1,714 433 1,388 192
2006 1,391 317 1,086 169
2007 1,256 301 603 167
Later Years - - - -
---------- ---------- ------- -------
Total Future Minimum
Lease Payments $ 8,619 $ 2,580 $ 6,457 $ 1,272
========== ========== ======= =======
OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated
unconsolidated special purpose entity. JMG has a capital structure of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from pollution control bonds and other bonds. JMG 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. The lease is accounted for as an
operating lease with the payment obligations included in the lease footnote.
Payments under the operating lease are based on JMG's cost of financing (both
debt and equity) and include an amortization component plus the cost of
administration. Neither OPCo nor AEP has an ownership interest in JMG and does
not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial
15-year lease term is non-cancelable. At the end of the initial term, OPCo can
renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or
sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition
cost, OPCo must pay the difference to JMG.
The use of JMG allows AEP to enter into an operating lease while keeping the tax
benefits otherwise associated with a capital lease. As of December 31, 2002,
unless the structure of this arrangement is changed, it is reasonably possible
that AEP will consolidate JMG in the third quarter of 2003 as a result of the
issuance of FIN 46. Upon consolidation, AEP would record the assets,
liabilities, depreciation expense, minority interest and debt interest expense
of JMG. AEP would eliminate operating lease expense. AEP's maximum exposure to
loss as a result of its involvement with JMG is approximately $560 million of
outstanding debt and equity of JMG as of December 31, 2002.
AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.
23. Lines of Credit and Sale of Receivables:
Lines of Credit - AEP System
The AEP System uses short-term debt, primarily commercial paper and revolving
credit facilities, to meet fluctuations in working capital requirements and
other interim capital needs. AEP has established a utility money pool and a
non-utility money pool to coordinate short-term borrowings for certain
subsidiaries. Utility money participants include AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC. AEP also incurs borrowings outside of the money
pool for other subsidiaries. As of December 31, 2002, AEP had revolving credit
facilities totaling $3.5 billion to support its commercial paper program. At
December 31, 2002, AEP had $3.2 billion outstanding in short-term borrowings of
which $1.4 billion was commercial paper supported by the revolving credit
facilities. The maximum amount of commercial paper outstanding during the year,
which had a weighted average interest rate during 2002 of 2.47%, was $3.3
billion during April 2002. On December 11, 2002, Moody's Investor Services
placed AEP's Prime-2 short-term rating for commercial paper under review for
possible downgrade. On January 24, 2003, Standard & Poor's Rating Services
placed AEP's A-2 short-term rating for commercial paper under review for
possible downgrade. On February 10, 2003, Moody's Investor Services downgraded
AEP's short-term rating for commercial paper to Prime-3 from Prime-2. As a
result, AEP's access to the commercial paper market will be limited and AEP will
use other sources of funds as necessary.
The registrant subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
AEGCo $0.4 $ 0.8 $ -
APCo 4.9 9.8 -
CSPCo 3.2 5.0 1.4
I&M 0.4 13.1 0.8
KPCo 1.8 2.3 -
OPCo 6.9 14.6 9.2
PSO 5.4 6.3 7.5
SWEPCo 4.6 3.4 4.2
TCC 11.1 11.4 16.9
TNC 3.8 3.1 2.7
Interest income earned from amounts advanced to the AEP money pool by the
registrant subsidiaries were:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
AEGCo $0.1 $ - $ -
APCo 2.0 1.7 -
CSPCo 1.3 0.8 1.1
I&M 2.0 1.6 9.0
KPCo - 0.1 1.8
OPCo 0.8 8.6 3.4
PSO 1.1 - -
SWEPCo 1.6 0.1 -
TCC 2.0 0.1 -
Outstanding short-term debt for AEP Consolidated consisted of:
December 31,
-----------
2002 2001
---- ----
(in millions)
Balance Outstanding:
Notes Payable $1,747 $1,063
Commercial paper 1,417 2,948
------ ------
Total $3,164 $4,011
====== ======
Sale of Receivables - AEP Credit
AEP Credit entered into a sale of receivables agreement with a group of banks
and commercial paper conduits. Under the sale of receivables agreement, which
expires May 28, 2003, AEP Credit sells an interest in the receivables it
acquires to the commercial paper conduits and banks and receives cash. This
transaction constitutes a sale of receivables in accordance with SFAS 140
allowing the receivables to be taken off of AEP Credit's balance sheet and
allowing AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities in
accordance with GAAP. We continue to service the receivables. This off-balance
sheet transaction was entered into to allow AEP credit to repay its outstanding
debt obligations, continue to purchase the AEP operating companies' receivables,
and accelerate its cash collections.
At December 31, 2002, the sale of receivables agreement provided the banks and
commercial paper conduits would purchase a maximum of $600 million of
receivables from AEP Credit, of which $454 million was outstanding. As
collections from receivables sold occur and are remitted, the outstanding
balance for sold receivables is reduced and as new receivables are sold, the
outstanding balance of sold receivables increases. All of the receivables sold
represented affiliate receivables. The commitment's new term under the sale of
receivables agreement will remain at $600 million until May 28, 2003. AEP Credit
maintains a retained interest in the receivables sold and this interest is
pledged as collateral for the collection of the 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.
AEP Credit purchases accounts receivable through purchase agreements with
affiliated companies and, until the first quarter of 2002, with non-affiliated
companies. As a result of the restructuring of electric utilities in the State
of Texas, the purchase agreement between AEP Credit and Reliant Energy,
Incorporated was terminated as of January 25, 2002 and the purchase agreement
between AEP Credit and Texas-New Mexico Power Company, the last remaining
non-affiliated company, was terminated on February 7, 2002. In addition, the
purchase agreements between AEP Credit and its Texas affiliates AEP Texas
Central Company (formerly Central Power and Light Company) and AEP Texas North
Company (formerly West Texas Utilities Company) were terminated effective March
20, 2002.
Comparative accounts receivable information for AEP Credit:
Year Ended December 31,
----------------------
2002 2001
---- ----
(in millions)
Proceeds from Sale of
Accounts Receivable $5,513 $1,134
Accounts Receivable
Retained Interest Less
Uncollectible Accounts
and Amounts Pledged as
Collateral 76 143
Deferred Revenue from
Servicing Accounts
Receivable 1 5
Loss on Sale of Accounts
Receivable 4 8
Average Variable
Discount Rate 1.92% 2.28%
Retained Interest if 10%
Adverse change in
Uncollectible Accounts 74 142
Retained Interest if 20%
Adverse change in
Uncollectible Accounts 72 140
Historical loss and delinquency amount for the AEP System's customer accounts
receivable managed portfolio:
Face Value
Year Ended December 31,
----------------------
2002 2001
(in millions)
Customer Accounts Receivable Retained $ 466 $ 343
Miscellaneous Accounts Receivable Retained 1,394 1,365
Allowance for Uncollectible Accounts Retained (119) (69)
------ ------
Total Net Balance Sheet Accounts Receivable 1,741 1,639
Customer Accounts Receivable Securitized (Affiliate) 454 560
Customer Accounts Receivable Securitized (Non-Affiliate) - 485
------ ------
Total Accounts Receivable managed $2,195 $2,684
====== ======
Net Uncollectible Accounts Written Off 48 72
------ ------
Customer accounts receivable retained and securitized for the domestic electric
operating companies are managed by AEP Credit. Miscellaneous account receivable
have been fully retained and not securitized.
At December 31, 2002, delinquent customer accounts receivable was $30 million.
Under the factoring arrangement certain of the registrant subsidiaries
(excluding AEGCo) sell without recourse certain of their customer accounts
receivable and accrued utility revenue balances to AEP Credit and are charged a
fee based on AEP Credit financing costs, uncollectible accounts experience for
each company's receivables and administrative costs. The costs of factoring
customer accounts receivable is reported as an operating expense. The amount of
factored accounts receivable and accrued utility revenues for each registrant
subsidiary was as follows:
December 31,
-----------
2002 2001
---- ----
Company (in millions)
- -------
APCo $ 67.6 $ 61.2
CSPCo 114.3 105.7
I&M 103.7 94.9
KPCo 29.5 26.2
OPCo 109.8 100.2
PSO 83.7 70.7
SWEPCo 65.2 81.6
TCC - 145.3
TNC - 35.5
The fees paid by the registrant subsidiaries to AEP Credit for factoring
customer accounts receivable were:
Year Ended December 31,
----------------------
2002 2001 2000
---- ---- ----
(in millions)
APCo $ 4.8 $ 5.2 $ -
CSPCo 15.8 15.2 10.8
I&M 7.4 8.5 6.8
KPCo 2.7 2.7 1.9
OPCo 11.4 12.8 8.4
PSO 7.2 9.6 8.3
SWEPCo 5.4 7.4 9.2
TCC 2.2 14.7 15.7
TNC 1.4 3.8 4.0
24. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows:
2002 Quarterly Periods Ended
----------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
(In Millions - Except
Per Share Amounts)
Revenues $3,169 $3,575 $3,870 $3,941
Operating Income (Loss) 459 427 782 (405)
Income (Loss) Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect 159 158 386 (682)
Net Income (Loss) (169) 62 425 (837)
Earnings (Loss) per Share
Before Discontinued
Operations,Extraordinary
Items and Cumulative
Effect* 0.49 0.49 1.14 (2.01)
Earnings (Loss) per
Share** (0.53) 0.19 1.25 (2.47)
2001 Quarterly Periods Ended
----------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
(In Millions - Except
Per Share Amounts)
Revenues $2,910 $3,259 $3,733 $2,865
Operating Income 521 622 824 215
Income Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect 230 251 399 37
Net Income 266 232 421 52
Earnings per Share Before
Discontinued Operations,
Extraordinary Items
and Cumulative Effect*** 0.72 0.77 1.23 0.12
Earnings per Share**** 0.83 0.72 1.31 0.16
* Amounts for 2002 do not add to $0.06 earnings per share before Discontinued
Operations, Extraordinary Items and Cumulative Effect due to rounding and the
dilutive effect of shares issued in 2002.
**Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.
***Amounts for 2001 do not add to $2.85 earnings per share before Discontinued
Operations, Extraordinary Items and Cumulative Effect due to rounding.
****Amounts for 2001 do not add to $3.01 earnings per share due to rounding.
The unaudited quarterly financial information for each AEP registrant subsidiary
follows:
Quarterly Periods Ended AEGCo APCo CSPCo I&M KPCo
(in thousands)
2002
March 31
Operating Revenues $49,875 $462,605 $314,826 $352,235 $ 99,185
Operating Income 1,767 81,554 45,548 30,363 15,484
Income Before
Extraordinary Items 1,893 55,341 33,858 11,058 10,246
Net Income 1,893 55,341 33,858 11,058 10,246
June 30
Operating Revenues $53,356 $432,015 $343,813 $369,043 $ 92,164
Operating Income 1,504 65,224 58,040 19,865 9,550
Income Before
Extraordinary Items 1,718 46,608 51,721 7,494 5,246
Net Income 1,718 46,608 51,721 7,494 5,246
September 30
Operating Revenues $55,988 $474,282 $428,437 $421,472 $100,359
Operating Income 1,436 81,365 89,033 57,004 11,119
Income Before Extraordinary Items 1,947 53,947 76,117 35,312 5,994
Net Income 1,947 53,947 76,117 35,312 5,994
December 31
Operating Revenues $54,062 $445,568 $313,084 $384,014 $ 86,975
Operating Income 1,422 73,920 27,158 43,957 6,044
Income (Loss) Before
Extraordinary Items 1,994 49,596 19,477 20,128 (919)
Net Income (Loss) 1,994 49,596 19,477 20,128 (919)
Quarterly Periods Ended OPCo PSO SWEPCo TCC TNC
----------------------- ---- --- ------ --- ---
(in thousands)
2002
March 31
Operating Revenues $520,652 $148,986 $222,259 $278,910 $103,626
Operating Income 83,716 8,410 22,469 55,445 11,145
Income (Loss) Before Extraordinary Items 64,051 (1,648) 8,159 24,445 3,992
Net Income (Loss) 64,051 (1,648) 8,159 24,445 3,992
June 30
Operating Revenues $521,365 $158,330 $263,074 $360,391 $104,452
Operating Income 61,046 20,201 31,988 64,319 5,547
Income Before Extraordinary Items 55,348 11,620 18,155 33,535 675
Net Income 55,348 11,620 18,155 33,535 675
September 30
Operating Revenues $566,366 $230,098 $362,423 $546,260 $152,667
Operating Income (Loss) 97,210 50,710 60,254 118,204 (308)
Income (Loss) Before Extraordinary Items 80,258 41,002 45,794 93,383 (4,193)
Net Income (Loss) 80,258 41,002 45,794 93,383 (4,193)
December 31
Operating Revenues $504,742 $256,233 $236,964 $504,932 $ 89,995
Operating Income (Loss) 56,357 5,400 27,758 155,765 (8,513)
Income (Loss) Before
Extraordinary Items 20,366 (9,914) 10,884 124,578 (14,151)
Net Income (Loss) 20,366 (9,914) 10,884 124,578 (14,151)
Quarterly Periods Ended AEGCo APCo CSPCo I&M KPCo
----------------------- ----- ---- ----- --- ----
(in thousands)
2001
March 31
Operating Revenues $60,507 $501,204 $327,437 $387,813 $100,681
Operating Income 1,807 88,152 51,932 52,698 12,604
Income Before Extaordinary Items 1,980 61,787 37,671 32,363 7,075
Net Income 1,980 61,787 37,671 32,363 7,075
June 30
Operating Revenues $52,217 $430,412 $333,995 $382,234 $ 89,541
Operating Income 1,882 59,362 62,894 47,340 8,364
Income Before Extrodinary Items 2,063 36,419 47,418 27,374 2,742
Net Income 2,063 36,419 21,011 27,374 2,742
September 30
Operating Revenues $57,417 $434,450 $375,691 $398,457 $ 96,197
Operating Income 1,615 60,381 76,920 44,509 12,587
Income Before Extraordinary Items 2,051 30,317 65,318 25,064 5,312
Net Income 2,051 30,317 65,318 25,064 5,312
December 31
Operating Revenues $57,407 $418,193 $313,196 $358,493 $ 92,606
Operating Income 1,673 67,091 60,431 15,158 14,123
Income (Loss) Before
Extraordinary Items 1,781 33,295 41,493 (9,013) 6,436
Net Income (Loss) 1,781 33,295 37,876 (9,013) 6,436
Quarterly Periods Ended OPCo PSO SWEPCo TCC TNC
----------------------- ---- --- ------ --- ---
(in thousands)
2001
March 31
Operating Revenues $552,503 $225,080 $267,117 $432,910 $141,649
Operating Income 64,756 8,340 33,986 64,152 5,392
Income (Loss) Before Extraordinary Items 53,397 (1,560) 19,869 35,031 891
Net Income (Loss) 53,397 (1,560) 19,869 35,031 891
June 30
Operating Revenues $512,196 $265,360 $271,748 $470,420 $139,228
Operating Income 47,067 21,942 32,649 82,351 12,428
Income Before Extraordinary Items 32,094 11,921 17,784 52,518 6,133
Net Income 10,579 11,921 17,784 52,518 6,133
September 30
Operating Revenues $535,535 $325,373 $331,441 $527,117 $181,433
Operating Income 69,668 59,914 60,194 112,598 17,745
Income Before Extraordinary Items 51,378 51,069 46,357 83,702 14,067
Net Income 51,378 51,069 46,357 83,702 14,067
December 31
Operating Revenues $497,871 $141,187 $231,020 $308,390 $ 94,148
Operating Income (Loss) 59,219 6,792 19,378 36,630 (2,175)
Income (Loss) Before
Extraordinary Items 28,924 (3,671) 5,357 13,536 (8,781)
Net Income (Loss) 32,091 (3,671) 5,357 11,027 (8,781)
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
for the fourth quarter 2002 decreased $896 million from the prior year due to
the impairment loss and impairment value losses of approximately $1,188 million
(pre-tax) to reduce the valuation of under-performing assets. In addition to the
impairments that were recorded during the fourth quarter, a change in AEP's
Accumulated Other Comprehensive Income (Loss) of $585 million for pension
liability had a negative effect on each registrant's Consolidated Balance
Sheets.
25. Trust Preferred Securities:
The following Trust Preferred Securities issued by the wholly-owned statutory
business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2002 and
December 31, 2001. They are classified on AEP's, PSO's, SWEPCo's and TCC's
Balance Sheets as Certain Subsidiary Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of
Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037.
TCC reacquired 490,000 trust preferred units during 2001.
Units
Issued/ Description of
Outstanding Underlying
Business Trust Security At 12/31/02 Amount at December 31, Debentures of Registrant
- -------------- -------- ----------- ---------------------- ------------------------
2002 2001
(in millions)
CPL Capital I 8.00%, Series A 5,450,000 $136 $136 TCC, $141 million,
8.00%, Series A
PSO Capital I 8.00%, Series A 3,000,000 75 75 PSO, $77 million,
8.00%, Series A
SWEPCo Capital I 7.875%, Series A 4,400,000 110 110 SWEPCO, $113 million,
---------- ---- ----
7.875%, Series A
12,850,000 $321 $321
========== ==== ====
Each of the business trusts is treated as a subsidiary of its parent company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified above. In addition to the obligations under
their subordinated debentures, each of the parent companies has also agreed to a
security obligation which represents a full and unconditional guarantee of its
capital trust obligation.
26. Minority Interest in Finance Subsidiary:
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne)
and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated
subsidiary of AEP that was capitalized with the assets of Houston Pipe Line
Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million
of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary
and parent of SubOne) preferred stock, that is convertible into AEP common stock
at market price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an unconditional
obligation to fund $83 million from SubOne and $750 million from Steelhead
Investors LLC ("Steelhead" - non-controlling preferred member interest). As
managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and has a capital structure of $750 million of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to
limit its risk associated with Houston Pipe Line Company and Louisiana
Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead receives a
quarterly preferred return equal to an adjusted floating reference rate (4.784%
and 4.413% for the quarters ended December 31, 2002 and 2001, respectively).
Caddis has the right to redeem Steelhead's interest at any time.
The $750 million invested in Caddis by Steelhead was loaned to SubOne. This
intercompany loan to SubOne is due August 2006, and is supported by the natural
gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4
million of preferred stock in AEP Gas Holding. The preferred stock is
convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if SubOne were to reduce its loan with Caddis by $225 million. The credit
agreement between Caddis and SubOne contains covenants that restrict certain
incremental liens and indebtedness, asset sales, investments, acquisitions, and
distributions. The credit agreement also contains covenants that impose minimum
financial ratios. Non-performance of these covenants may result in an event of
default under the credit agreement. Through December 31, 2002, we have complied
with the covenants contained in the credit agreement. In addition, a default
under any other agreement or instrument relating to AEP and certain
subsidiaries' debt outstanding in excess of $50 million is an event of default
under the credit agreement.
The initial period of Steelhead's investment in Caddis is through August 2006.
At the end of the initial period, Caddis will either reset Steelhead's return
rate, re-market Steelhead's interests to new investors, redeem Steelhead's
interests, in whole or in part including accrued return, or liquidate Caddis in
accordance with the provisions of applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events including a default in the payment of the preferred
return, Steelhead's rights include: forcing a liquidation of Caddis and acting
as the liquidator, and requiring the conversion of the AEP Gas Holding preferred
stock into AEP common stock. If Steelhead exercised its rights to force Caddis
to liquidate under these conditions, then AEP would evaluate whether to
refinance at that time or relinquish the assets that support the intercompany
loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are separate and
legally distinct from AEP. The results of operations, cash flows and financial
position of Caddis and SubOne are consolidated with AEP for financial reporting
purposes. Steelhead's investment in Caddis and payments made to Steelhead from
Caddis are currently reported on AEP's consolidated statements of operation and
consolidated balance sheets as Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with Steelhead is
$321.4 million of preferred stock, $83 million under the subscription agreement
to Caddis for any losses incurred by Caddis and the cash reserve fund balance of
$34 million (as of December 31, 2002) due Caddis for default under the
intercompany loan agreement. AEP can reduce its maximum exposure related to the
preferred stock by a reduction of $225 million of the intercompany loan.
As of December 31, 2002, we are continuing to review the application of FIN 46
as it relates to the Steelhead transaction.
27. Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per unit and received
proceeds of $345 million. Each equity unit consists of a forward purchase
contract and a senior note.
The forward purchase contracts obligate the holders to purchase shares of AEP
common stock on August 16, 2005. The purchase price per equity unit is $50. The
number of shares to be purchased under the forward purchase contract will be
determined under a formula based upon the average closing price of AEP common
stock near the stock purchase date. Holders may satisfy their obligation to
purchase AEP common stock under the forward purchase contracts by allowing the
senior notes to be remarketed or by continuing to hold the senior notes and
using other resources as consideration for the purchase of stock. If the holders
elect to allow the notes to be remarketed, the proceeds from the remarketing
will be used to purchase a portfolio of U.S. treasury securities that the
holders will pledge to AEP in order to meet their obligations under the forward
purchase contracts.
The senior notes have a principal amount of $50 each and mature on August 16,
2007. The senior notes are the collateral that secures the holders' requirement
to purchase common stock under the forward purchase contracts.
AEP will make quarterly interest payments on the senior notes at the initial
annual rate of 5.75%. The interest rate can be reset through a remarketing,
which is initially scheduled for May 2005. AEP will make contract adjustment
payments to the purchaser at the annual rate of 3.50% on the forward purchase
contracts. The present value of the contract adjustment payments has been
recorded as a $31 million liability in Equity Unit Senior Notes offset by a
charge to Paid-in Capital. Interest payments on the senior notes are reported as
interest expense. Accretion of the contract adjustment payment liability is
reported as interest expense.
AEP 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.
28. Jointly Owned Electric Utility Plant:
CSPCo, PSO, SWEPCo, TCC and TNC have generating units that are jointly owned
with unaffiliated companies. Each of the participating companies is obligated to
pay its share of the costs of any such jointly owned facilities in the same
proportion as its ownership interest. Each AEP registrant subsidiary's
proportionate share of the operating costs associated with such facilities is
included in its statements of income and the investments are reflected in its
balance sheets under utility plant as follows:
Company's Share
December 31,
---------------
2002 2001
-------------------------- ---------------------------
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
--------- ------------ ------------- ------------ ------------
(in thousands) (in thousands)
CSPCo:
W.C. Beckjord Generating Station
(Unit No. 6) 12.5 $ 15,487 $ 49 $ 14,292 $ 884
Conesville Generating Station
(Unit No. 4) 43.5 81,960 279 81,697 494
J.M. Stuart Generating Station 26.0 197,276 44,865 193,760 27,758
Wm. H. Zimmer Generating Station 25.4 705,620 14,077 704,951 2,634
Transmission (a) 61,187 2,281 61,476 91
---------- ------- ---------- -------
$1,061,530 $61,551 $1,056,176 $31,861
========== ======= ========== =======
PSO:
Oklaunion Generating Station
(Unit No. 1) 15.6 $ 83,562 $ 777 $ 82,646 $ 634
========== ======= ========== ========
SWEPCo:
Dolet Hills Generating Station
(Unit No. 1) 40.2 $ 235,366 1,313 $ 234,747 $ 675
Flint Creek Generating Station
(Unit No. 1) 50.0 91,567 1,052 83,953 213
Pirkey Generating Station
(Unit No. 1) 85.9 451,136 2,197 439,430 10,577
---------- ------- ---------- -------
$ 778,069 $ 4,562 $ 758,130 $11,465
========== ======= ========== ========
TCC:
Oklaunion Generating Station
(Unit No. 1) 7.8 $ 38,055 $ 369 $ 37,728 $ 318
South Texas Project Generating
Station (Units No. 1 and 2) 25.2 2,364,359 43,887 2,360,452 41,571
---------- ------- ---------- -------
$2,402,414 $44,256 $2,398,180 $41,889
========== ======= ========== ========
TNC:
Oklaunion Generating Station
(Unit No. 1) 54.7 $ 277,946 $ 3,650 $ 279,419 $ 1,651
========== ======= ========== =======
(a) Varying percentages of ownership.
The accumulated depreciation with respect to each AEP registrant subsidiary's
share of jointly owned facilities is shown below:
December 31,
-----------
2002 2001
---- ----
(in thousands)
CSPCo $436,683 $410,756
PSO 49,085 35,653
SWEPCo 450,057 392,728
TCC 927,193 863,130
TNC 102,542 100,430
29. Related Party Transactions
AEP System Power Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement,
dated July 6, 1951, as amended (the Interconnection Agreement), defining how
they share the costs and benefits associated with their generating plants. This
sharing is based upon each company's "member-load-ratio," which is calculated
monthly on the basis of each company's maximum peak demand in relation to the
sum of the maximum peak demands of all five companies during the preceeding 12
months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been
parties to the AEP System Interim Allowance Agreement which provides, among
other things, for the transfer of SO2 Allowances associated with transactions
under the Interconnection Agreement. As part of AEP's restructuring settlement
agreement filed with FERC, under certain conditions CSPCo and OPCo would no
longer be parties to the Interconnection Agreement and certain other
modifications to its terms would also be made.
Power marketing and trading transactions (trading activities) are conducted by
the AEP Power Pool and shared among the parties under the Interconnection
Agreement. Trading activities involve the purchase and sale of electricity under
physical forward contracts at fixed and variable prices and the trading of
electricity contracts including exchange traded futures and options and
over-the-counter options and swaps. The majority of these transactions represent
physical forward contracts in the AEP System's traditional marketing area and
are typically settled by entering into offsetting contracts.
In addition, the AEP Power Pool enters into transactions for the purchase and
sale of electricity options, futures and swaps, and for the forward purchase and
sale of electricity outside of the AEP System's traditional marketing area.
PSO, SWEPCo, TCC, TNC and AEP Service Corporation are parties to a Restated and
Amended Operating Agreement originally dated as of January 1, 1997 (CSW
Operating Agreement). The CSW Operating Agreement requires the operating
companies of the west zone to maintain specified annual planning reserve margins
and requires the operating companies that have capacity in excess of the
required margins to make such capacity available for sale to other operating
companies as capacity commitments. The CSW Operating Agreement also delegates to
AEP Service Corporation the authority to coordinate the acquisition,
disposition, planning, design and construction of generating units and to
supervise the operation and maintenance of a central control center. As part of
AEP's restructuring settlement agreement filed with the FERC, under certain
conditions TCC and TNC would no longer be parties to the CSW Operating
Agreement.
AEP's System Integration Agreement provides for the integration and coordination
of AEP's east and west zone operating subsidiaries, joint dispatch of generation
within the AEP System, and the distribution, between the two operating zones, of
costs and benefits associated with the System's generating plants. It is
designed to function as an umbrella agreement in addition to the AEP
Interconnection Agreement and the CSW Operating Agreement, each of which will
continue to control the distribution of costs and benefits within each zone.
The following table shows the revenues derived from sales to the Pools and
direct sales to affiliates for years ended December 31, 2002, 2001 and 2000:
APCo CSPCo I&M KPCo OPCo AEGCo
Related Party Revenues (in thousands)
2002 Sales to East System Pool $106,651 $42,986 $ 197,525 $ 22,369 $397,248 $ -
Sales to West System Pool 18,300 12,107 13,036 4,717 16,265 -
Direct Sales To East Affiliates 58,213 - - - 50,599 213,071
Direct Sales To West Affiliates - - - - - -
Other 3,313 2,109 3,577 878 1,090 -
-------- ------- ---------- -------- -------- --------
Total Revenues $186,477 $57,202 $ 214,138 $ 27,964 $465,202 $213,071
======== ======= ========== ======== ======== ========
2001 Sales to East System Pool $ 91,977 $44,185 $ 239,277 $ 34,735 $431,637 $ -
Sales to West System Pool 24,892 13,971 15,596 6,117 19,797 -
Direct Sales To East Affiliates 54,777 - - - 55,450 227,338
Direct Sales To West Affiliates (3,133) (1,705) (1,905) (744) (2,590) -
Other 2,772 11,060 2,071 2,258 7,072 -
-------- ------- ---------- -------- -------- --------
Total Revenues $171,285 $67,511 $ 255,039 $ 42,366 $511,366 $227,338
======== ======= ========== ======== ======== ========
2000 Sales to East System Pool $ 81,013 $36,884 $ 200,474 $ 36,554 $502,140 $ -
Sales to West System Pool 7,697 4,095 4,614 1,829 6,356 -
Direct Sales To East Affiliates 59,106 - - - 66,487 227,983
Direct Sales To West Affiliates 4,092 2,262 2,510 972 3,421 -
Other 2,770 6,124 2,710 2,466 4,043 -
-------- ------- ---------- -------- -------- --------
Total Revenues $154,678 $49,365 $ 210,308 $ 41,821 $582,447 $227,983
======== ======= ========== ======== ======== ========
PSO SWEPCo TCC TNC
Related Party Revenues (in thousands)
2002 Sales to East System Pool $ - $ - $ - $ -
Sales to West System Pool 674 1,334 18,416 1,280
Direct Sales To East Affiliates 611 270 366 (23)
Direct Sales To West Affiliates 6,047 75,674 956,751 228,404
Other 2,107 (4,979) 32,911 10,764
------- ------- ---------- --------
Total Revenues $ 9,439 $72,299 $1,008,444 $240,425
======= ======= ========== ========
2001 Sales to East System Pool $ 4 $ - $ - $ -
Sales to West System Pool 3,317 8,073 19,865 322
Direct Sales To East Affiliates 2,833 3,238 3,697 1,228
Direct Sales To West Affiliates 30,668 67,930 12,617 9,350
Other (51) (4) 5,583 7,781
------- ------- ---------- --------
Total Revenues $36,771 $79,237 $ 41,762 $ 18,681
======= ======= ========== ========
2000 Sales to East System Pool $ - $ - $ - $ -
Sales to West System Pool 7,323 5,546 23,421 194
Direct Sales To East Affiliates (1,990) (3,008) (3,348) (1,116)
Direct Sales To West Affiliates 21,995 62,178 12,516 7,645
Other (12,680) (1,592) 5,163 11,931
------- ------- ---------- --------
Total Revenues $14,648 $63,124 $ 37,752 $ 18,654
======= ======= ========== ========
The following table shows the purchased power expense incurred from purchases
from the Pools and affiliates for the years ended December 31, 2002, 2001, and
2000:
APCo CSPCo I&M KPCo OPCo
Related Party Purchases (in thousands)
2002 Purchases from East System Pool $233,677 $309,999 $ 83,918 $ 68,846 $70,338
Purchases from West System Pool 337 219 237 86 297
Direct Purchases from East Affiliates 583 387 149,569 64,070 519
Direct Purchases from West Affiliates - - - - -
-------- -------- -------- -------- -------
Total Purchases $234,597 $310,605 $233,724 $133,002 $71,154
======== ======== ======== ======== =======
2001 Purchases from East System Pool $346,582 $292,034 $ 79,030 $ 61,816 $62,350
Purchases from West System Pool 296 165 185 72 235
Direct Purchases from East Affiliates - - 159,022 68,316 -
Direct Purchases from West Affiliates - - - - -
-------- -------- -------- -------- -------
Total Purchases $346,878 $292,199 $238,237 $130,204 $62,585
======== ======== ======== ======== =======
2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 $50,339
Purchases from West System Pool 455 260 285 108 390
Direct Purchases from East Affiliates - - 158,537 69,446 -
Direct Purchases from West Affiliates 14 8 9 3 12
-------- -------- -------- -------- -------
Total Purchases $355,774 $287,750 $265,475 $127,707 $50,741
======== ======== ======== ======== =======
PSO SWEPCo TCC TNC
Related Party Purchases (in thousands)
2002 Purchases from East System Pool $ 343 $ - $ - $ -
Purchases from West System Pool 874 (456) 1,366 15,475
Direct Purchases from East Affiliates 29,029 17,242 8,236 2,669
Direct Purchases from West Affiliates 59,208 25,236 13,804 19,438
------- ------- ------- -------
Total Purchases $89,454 $42,022 $23,406 $37,582
======= ======= ======= =======
2001 Purchases from East System Pool $ 1,327 $ - $ - $ 4
Purchases from West System Pool 5,877 3,810 415 11,689
Direct Purchases from East Affiliates 1,951 2,352 12,657 4,614
Direct Purchases from West Affiliates 34,603 9,696 45,569 40,349
------- ------- ------- -------
Total Purchases $43,758 $15,858 $58,641 $56,656
======= ======= ======= =======
2000 Purchases from East System Pool $20,100 $ - $ - $ -
Purchases from West System Pool 5,386 4,379 1,696 18,444
Direct Purchases from East Affiliates 2,117 695 251 71
Direct Purchases from West Affiliates 33,185 8,264 30,644 39,258
------- ------- ------- -------
Total Purchases $60,788 $13,338 $32,591 $57,773
======= ======= ======= =======
The above summarized related party revenues and expenses are reported in their
entirety, without elimination, and are presented as operating revenues
affiliated and purchased power affiliated on the statements of operations of
each AEP Power Pool member. Since all of the above pool members are included in
AEP's consolidated results, the above summarized related party transactions are
eliminated in total in AEP's consolidated revenues and expenses.
AEP System Transmission Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated
April 1, 1984, as amended (the Transmission Agreement), defining how they share
the costs associated with their relative ownership of the extra-high-voltage
transmission system (facilities rated 345 kv and above) and certain facilities
operated at lower voltages (138 kv and above). Like the Interconnection
Agreement, this sharing is based upon each company's "member-load-ratio."
The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 2002,
2001 and 2000:
2002 2001 2000
---- ---- ----
(in thousands)
APCo $(13,400) $ (3,100) $ (3,400)
CSPCo 42,200 40,200 38,300
I&M (36,100) (41,300) (43,800)
KPCo (5,400) (4,600) (6,000)
OPCo 12,700 8,800 14,900
PSO, SWEPCo, TCC, TNC and AEP Service Corporation are parties to a Transmission
Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA
established a coordinating committee, which is charged with the responsibility
of overseeing the coordinated planning of the transmission facilities of the
west zone operating subsidiaries, including the performance of transmission
planning studies, the interaction of such subsidiaries with independent system
operators (ISO) and other regional bodies interested in transmission planning
and compliance with the terms of the Open Access Transmission Tariff (OATT)
filed with the FERC and the rules of the FERC relating to such tariff.
Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT.
The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 2002,
2001 and 2000:
2002 2001 2000
---- ---- ----
(in thousands)
PSO $(4,200) $ (4,000) $ (3,300)
SWEPCo (5,000) (5,400) (5,900)
TCC 3,600 3,900 3,400
TNC 5,600 5,500 5,800
AEP's System Transmission Integration Agreement provides for the integration and
coordination of the planning, operation and maintenance of the transmission
facilities of AEP's east and west zone operating subsidiaries. Like the System
Integration Agreement, the System Transmission Integration Agreement functions
as an umbrella agreement in addition to the AEP Transmission Agreement and the
Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:
o The allocation of transmission costs and revenues.
o The allocation of third-party transmission costs and revenues and
System dispatch costs.
The Transmission Integration Agreement anticipates that additional service
schedules may be added as circumstances warrant.
Unit Power Agreements and Other
A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides
for the sale by AEGCo to I&M of all the power (and the energy associated
therewith) available to AEGCo at the Rockport Plant unless it is sold to another
utility. I&M is obligated, whether or not power is available from AEGCo, to pay
as a demand charge for the right to receive such power (and as an energy charge
for any associated energy taken by I&M) such amounts, as when added to amounts
received by AEGCo from any other sources, will be at least sufficient to enable
AEGCo to pay all its operating and other expenses, including a rate of return on
the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power
Agreement will continue in effect until the expiration of the lease term of Unit
2 of the Rockport Plant unless extended in specified circumstances.
Pursuant to an assignment between I&M and KPCo, and a unit power agreement
between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo has agreed to pay to AEGCo in consideration for the right to receive such
power the same amounts which I&M would have paid AEGCo under the terms of the
I&M Power Agreement for such entitlement. The KPCo unit power agreement expires
on December 31, 2004. This unit power agreement extends until December 31, 2009
for Unit 1 and until December 7, 2022 for Unit 2 if AEP's restructuring
settlement agreement filed with the FERC becomes operative.
APCo and OPCo, jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership interests. Each
company's share of these costs is included in the appropriate expense accounts
on each company's consolidated statements of income. Each company's investment
in these plants is included in electric utility plant on its consolidated
balance sheets.
I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from
barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid
to I&M for barging services as fuel expense. The amount of affiliated revenues
and affiliated expenses were:
Year Ended December 31,
2002 2001 2000
---- ---- ----
Company (in millions)
I&M - revenues $34.3 $30.2 $23.5
AEGCo - expense 7.8 8.5 8.8
APCo - expense 12.8 11.5 7.8
OPCo - expense 7.9 10.2 6.9
Memco - expense 5.7 - -
AEP Energy Services 0.1 - -
American Electric Power Service Corporation (AEPSC) provides certain managerial
and professional services to AEP System companies. The costs of the services are
billed to its affiliated companies by AEPSC on a direct-charge basis, whenever
possible, and on reasonable bases of proration for shared services. The billings
for services are made at cost and include no compensation for the use of equity
capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services rendered. AEPSC
and its billings are subject to the regulation of the SEC under the PUHCA.
30. Subsequent Events (Unaudited):
Common Stock Offering - On February 27, 2003, AEP priced its offering of 50
million shares of common stock at a public offering price of $20.95 per share.
AEP has granted the underwriters an option to purchase an additional 7.5 million
shares of common stock to cover overallotments. The net proceeds from the sale
of these securities will be used to reduce debt and for general corporate
purposes.
Senior Notes Offering - During March 2003, AEP completed an offering of 5.375%
Series C Senior Notes which have a principal amount of $500 million and a
maturity date of March 15, 2010. The net proceeds from the offering will be used
to repay or redeem current maturities of long-term debt, a portion of our
minority interest in a financing subsidiary, and for general corporate purposes.
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS
The following is a combined presentation of management's discussion and analysis
of financial condition, accounting policies and other matters for AEP and its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its subsidiary registrants is presented with
their financial statements earlier in this document. The following is a list of
sections of management's discussion and analysis of financial condition,
accounting policies and other matters and the registrant to which they apply:
Financial Condition AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Critical Accounting AEP, AEGCo, APCo,
Policies CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Market Risks AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Industry Restructuring AEP, APCo, CSPCo
I&M, KPCo, OPCo,
PSO, SWEPCo, TCC,
TNC
Litigation AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo,
TCC, TNC
Environmental Concerns AEP, AEGCo, APCo,
and Issues CSPCo, I&M, KPCo
OPCo, PSO,
SWEPCo, TCC, TNC
Other Matters AEP, AEGCo, APCo,
CSPCo, I&M, KPCo,
OPCo, PSO,
SWEPCo, TCC, TNC
Financial Condition
We measure our financial condition by the strength of the balance sheets and the
liquidity provided by cash flows and earnings.
Balance sheet capitalization ratios and cash flow ratios are principal
determinants of our credit quality.
Credit Ratings
The rating agencies have been conducting credit reviews of AEP and its
registrant subsidiaries. The agencies are also reviewing most companies in the
energy sector due to issues which impact the entire industry, not only AEP and
its subsidiaries.
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review were downgrades of
the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1
to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1.
TNC, which had no senior unsecured notes outstanding at the time of the ratings
action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial
paper was also concurrently downgraded from P-2 to P-3. The completion of this
review was a culmination of earlier ratings action in 2002 that had included a
downgrade of AEP from Baa1 to Baa2 and the placement of five of the registrant
subsidiaries on negative outlook. With the completion of the reviews, Moody's
has placed AEP and its rated subsidiaries on stable outlook.
In February 2003, Standard & Poor's placed AEP's senior unsecured debt and
commercial paper ratings on credit watch with negative implications, and did the
same with the subsidiaries. S&P indicated that resolution regarding these
actions would come within a short time (see additional discussion in Financing -
Credit Ratings in Item 1 of Part I).
In 2002, Fitch Ratings Service downgraded both PSO and SWEPCo from A to A- for
the senior unsecured notes. Fitch has AEP and its subsidiaries on stable outlook
and the commercial paper rating is stable at F-2 (see additional discussion in
Financing - Credit Ratings in Item 1 of Part I).
Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the
following table:
Company Moody's S&P Fitch
- ------- ------- --- -----
APCo Baa1 BBB+ A-
CSPCo A3 BBB+ A
I&M Baa1 BBB+ BBB+
KPCo Baa1 BBB+ BBB+
OPCo A3 BBB+ A-
PSO A3 BBB+ A
SWEPCO A3 BBB+ A
TCC Baa1 BBB+ A
TNC A3 BBB+ A
Current short-term ratings are as follows:
Company Moody's S&P Fitch
- ------- ------- --- -----
AEP P-3 A-2 F-2
The current ratings for senior unsecured debt are listed in the following table:
Company Moody's S&P Fitch
- ------- ------- --- -----
AEP Baa3 BBB+ BBB+
AEP Resources* Baa3 BBB+ BBB+
APCo Baa2 BBB+ BBB+
CSPCo A3 BBB+ A-
I&M Baa2 BBB+ BBB
KPCo Baa2 BBB+ BBB
OPCo A3 BBB+ BBB+
PSO Baa1 BBB+ A-
SWEPCO Baa1 BBB+ A-
TCC Baa2 BBB+ A-
TNC Baa1 BBB+ A-
* The rating is for a series of senior notes issued
with a Support
Agreement from AEP.
AEP's common equity to total capitalization declined to 32% in 2002 from 36% in
2001 and 37% in 2000. Total capitalization includes long-term debt due within
one year, equity unit senior notes, minority interest and short-term debt.
Preferred stock at 1% remained unchanged. In 2002, long-term debt including
equity unit senior notes and trust preferred securities increased from 43% to
50% while Short-term Debt decreased from 17% to 14% and Minority Interest in
Finance Subsidiary remained unchanged at 3%. In 2001 Long-term Debt remained
unchanged while Short-term Debt decreased from 20% to 17% and Minority Interest
in Finance Subsidiary increased to 3%. In 2002, 2001 and 2000, AEP did not issue
any shares of common stock to meet the requirements of the Dividend Reinvestment
and Direct Stock Purchase Plan and the Employee Savings Plan. Common stock was
issued in 2002 for stock options exercised and under an equity offering
(discussed in Financing Activity).
Liquidity
- ---------
Liquidity, or access to cash, has become a more critical factor in determining
the financial stability of a company due to volatility in wholesale power
markets and the potential limitations that credit rating downgrades place on a
company's ability to raise capital. Management is committed to preserving an
adequate liquidity position and addressing AEP and its subsidiaries' financial
needs in 2003.
As of December 31, 2002, we had an available liquidity position of $3.5 billion
as illustrated in the table below:
Credit Facilities
- -----------------
(in millions) Maturity
Commercial Paper Backup
Lines of Credit $2,500* 5/03
Commercial Paper Backup
Lines of Credit 1,000 5/05
Corporate Separation
Revolving Credit 1,725 4/03
Euro Revolving Credit
Facilities 315 10/03
------
Total 5,540
Cash
Liquidity Reserve 1,000**
------
Total Credit Facilities
and Cash 6,540
Less: Commercial Paper
Outstanding
Corporate Separation 1,415
Loans 1,300
Euro Revolving
Credit Loans 305
------
Total Available Liquidity $3,520
======
* Contains one year term-out provision.
** Unrestricted and excludes $213 million
of operational cash on hand.
AEP and its subsidiaries' goal for 2003 is to use cash from operations to fund
capital expenditures, dividend payments and working capital requirements.
Short-term debt is used as an interim bridge for timing differences in the need
for cash or to fund debt maturities until permanent financing is arranged.
Short-term funding comes from the parent company's commercial paper program and
revolving credit facilities. Proceeds are loaned to the subsidiaries through
intercompany notes. AEP and its subsidiaries also operate a non-utility and
utility money pool to minimize the AEP System's external short-term funding
requirements and sell accounts receivable to provide liquidity for the domestic
electric subsidiaries. The commercial paper program is backed by $3.5 billion in
bank facilities of which $1 billion matures in May 2005. The remaining $2.5
billion matures in May 2003 and has a one-year term-out provision at AEP's
option. At December 31, 2002, approximately $1.4 billion of commercial paper was
outstanding. A portion of the commercial paper balance is related to funding of
debt maturities of the Ohio and Texas subsidiaries pending a permanent financing
program. The Ohio and Texas subsidiaries issued $2,025 million of senior
unsecured notes in February 2003 with maturity dates ranging from 2005 to 2033.
The commercial paper balance outstanding decreased in early 2003 due to
repayment with proceeds from these issuances.
AEP also has a $1.725 billion bank facility maturing in April 2003 that is
available for debt refinancing. At December 31, 2002, $1.3 billion was
outstanding under that facility. With the issuance of the permanent financing
for the Ohio and Texas subsidiaries mentioned above, this facility was repaid
and cancelled in February 2003.
AEP also has revolving credit facilities in place for 300 million Euros to
support the wholesale business in Europe. At December 31, 2002, the majority of
these facilities were drawn.
AEP also maintains a minimum $300 million cash liquidity reserve fund to support
its marketing operations in the U.S. and keeps additional cash on hand as market
conditions change. At December 31, 2002, AEP had $1 billion of cash available
for liquidity.
On December 6, 2002, we closed a 364-day, $425 million facility and used it to
partially repay the maturing interim financing for the U.K. generation plants
(FFF). The facility was secured by a pledge of the shares of AEP companies in
the FFF ownership chain and guaranteed by the parent company. A portion ($213
million) of the facility is due in May 2003. The remainder of the FFF interim
financing was repaid using a combination of existing funds and draws against the
Euro revolving credit facilities.
In total, we had approximately $6.5 billion in liquidity sources of which $3.5
billion were unused and available at December 31, 2002.
During 2002, cash flow from operations was $1.7 billion, including $21 million
from Net Income Before Discontinued Operations, Extraordinary Items and
Cumulative Effect, approximately $1.3 billion from depreciation, amortization,
deferred taxes, and deferred investment tax credits, approximately $1.1 billion
associated with asset, investment value and other impairments, offset by
additional working capital requirements of approximately $700 million. These
additional working capital requirements reflect the one time impact of the
discontinuance of the sale of accounts receivable for Texas companies and
billing delays related to the transition to customer choice in Texas, higher
margin requirements for gas trading, seasonal fuel inventory growth, and other
miscellaneous items. Construction expenditures were $1.7 billion including major
expenditures for emission control technology on several coal-fired generating
units (see discussion in Note 9). Dividends on common stock were $793 million.
Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the
Texas REPs and the issuance of common stock, common equity units, 15-year notes
for a wind generation project and transition funding bonds provided funds to
reduce debt, fund construction and pay dividends.
During 2001, AEP's cash flow from operations was $2.8 billion, including $885
million from Net Income Before Discontinued Operations, Extraordinary Items and
Cumulative Effect and $1.4 billion from depreciation, amortization, deferred
taxes and deferred investment tax credits. Capital expenditures including
acquisitions were $3.9 billion and dividends on common stock were $773 million.
Cash from operations less dividends on common stock financed 51% of capital
expenditures.
During 2001, the proceeds of AEP's $1.25 billion global notes issuance and
proceeds from the sale of a U.K. distribution company and two generating plants
provided cash to purchase assets, fund construction, retire debt and pay
dividends. Major construction expenditures include amounts for a wind generating
facility and emission control technology on several coal-fired generating units.
Asset purchases include HPL, coal mines, a barge line, a wind generating
facility and two coal-fired generating plants in the U.K. These acquisitions
accounted for the increase in total debt during 2001. Long-term funding
arrangements for specific assets are often complex and typically not completed
until after the acquisition.
The loss for 2002 resulted in a negative dividend payout ratio of 153%
reflecting the losses on sale and impairments of assets. Earnings for 2001
resulted in a dividend payout ratio of 80%, a considerable improvement over the
289% payout ratio in 2000. The abnormally high ratio in 2000 was the result of
the adverse impact on 2000 earnings from the Cook Plant extended outage and
related restart expenditures, merger costs and the write-off related to COLI and
non-regulated subsidiaries.
AEP and its subsidiaries generally use short-term borrowings to fund property
acquisitions and construction until long-term funding mechanisms are arranged.
Some acquisitions of existing business entities include the assumption of their
outstanding debt and certain liabilities. Sources of long-term funding include
issuance of AEP common stock, minority interest or long-term debt and
sale-leaseback or leasing arrange-ments. The domestic electric subsidiaries
generally issue short-term debt to provide for interim financing of capital
expenditures that exceed internally generated funds and periodically reduce
their outstanding short-term debt through issuances of long-term debt and
additional capital contributions from their parent company.
AEP's revolving credit agreements include covenants that require performance of
certain actions, including maintaining specified financial ratios.
Non-performance of these covenants may result in an event of default under these
credit agreements. At December 31, 2002, AEP complied with the covenants
contained in these credit agreements. In addition, a default under any other
agreement or instrument relating to debt outstanding in excess of $50 million is
an event of default under these credit agreements. An event of default under
these credit agreements would cause all amounts outstanding thereunder to be
immediately payable.
Financing Activity
- ------------------
Common Stock
In June 2002, AEP issued 16 million shares of common stock at $40.90 per share
through an equity offering and received net proceeds of $634 million. Proceeds
from the sale of equity units and common stock were used to pay down short-term
debt and establish a cash liquidity reserve fund.
Equity Units
In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345
million). See Note 27 for additional information.
Debt
In February 2002, TCC issued $797 million of securitization notes that were
approved by the PUCT as part of Texas restructuring to recover generation
related regulatory assets. The proceeds were used to reduce TCC's debt and
equity.
In April 2002, AEP closed on a bridge loan facility consisting of a $1.125
million 364-day revolving credit facility and a $600 million 364-day term loan
facility to prepare for corporate separation. At year-end, $600 million was
borrowed under the term loan facility and $700 million was borrowed under the
revolving credit facility. Those amounts were repaid and the facility terminated
when bonds were issued by CSPCo, OPCo, TCC and TNC in February 2003.
In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013
at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The use of
proceeds from the above bonds was repayment of the bridge loan facility
mentioned above, repayment of short-term debt, and for general corporate
purposes.
In 2002, the following issuances were completed by the subsidiaries of AEP:
- ------------ ---------------- ----------- ----------- -------
Principal
Amount
(in
mil-
Com-pany Type of Debt lions) Interest Due
Rate Date
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
APCo Unsecured Notes $450 4.80% 2005
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
APCo Unsecured Notes 200 4.32%* 2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Installment
I&M Purchase 50 4.90% 2025
Contracts
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
I&M Unsecured Notes 150 6.0% 2032
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
I&M Unsecured Notes 100 6 3/8% 2012
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
KPCo Unsecured Notes 125 5.50% 2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
KPCo Unsecured Notes 80 4.32%* 2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
KPCo Unsecured Notes 70 4.37%* 2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
PSO Unsecured Notes 200 6.00% 2032
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Senior
SWEPCo Unsecured Notes 200 4.50% 2005
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Other Notes Payable 121 6.20%- 2017
Subsid-iaries 6.60%
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Other Revolving 305 Variable 2003
Subsid-iariesCredit
- ------------ ---------------- ----------- ----------- -------
- -------------------------------------------------------------
* Interest rate payable by subsidiary in U.S. dollars. While these companies do
not have an Australian rate obligation, there is an underlying interest rate to
Australian investors in Australian dollars of either 6% or a variable rate.
- -------------------------------------------------------------
The subsidiaries also redeemed approximately $2 billion of long-term debt in
2002. See the Schedule of Long-term Debt for each registrant in sections B to K
for details.
AEP uses money pools to meet the short-term borrowings for the majority of its
subsidiaries In addition, AEP also funds the short-term debt requirements of
other subsidiaries that are not included in the money pool. As of December 31,
2002, AEP had credit facilities totaling $3.5 billion to support its commercial
paper program. At December 31, 2002, AEP had $1.4 billion outstanding in
short-term borrowings subject to these credit facilities.
AEP Credit purchases, without recourse, the accounts receivable of most of the
domestic utility operating companies. AEP Credit's financing for the purchase of
receivables changed in December 2001. Starting December 31, 2001, AEP Credit
entered into a sale of receivables agreement. The agreement allows AEP Credit to
sell certain receivables and receive cash meeting the requirements of SFAS 140
for the receivables to be removed from AEP's and the subsidiaries' Balance
Sheets. At December 31, 2002, AEP Credit had $454 million sold under this
agreement. See Note 23 for further discussion.
Off-balance Sheet and Minority Interest Arrangements
AEP and its subsidiaries enter into off-balance sheet arrangements for various
reasons ranging from accelerating cash collections, reducing operational expense
to spreading risk of loss to third parties. The following identifies significant
off-balance sheet arrangements:
Power Generation Facility
AEP has entered into agreements with Katco Funding L.P. (Katco), an unrelated
unconsolidated special purpose entity. Katco has an aggregate financing
commitment of $525 million and a capital structure of which 3% is equity from
investors with no relationship to AEP or any of its subsidiaries and 97% is debt
from a syndicate of banks. Katco was formed to develop, construct, finance and
lease a power generation facility to AEP. Katco will own the power generation
facility and lease it to AEP after construction is completed. The lease will be
accounted for as an operating lease (see Note 22), therefore neither the
facility nor the related obligations are reported on AEP's Consolidated Balance
Sheets. Payments under the operating lease are expected to commence in the first
quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company
(DOW), which will use the energy produced by the facility and sell excess
energy. AEP has agreed to purchase the excess energy from DOW for resale. The
use of Katco allows AEP to limit its risk associated with the power generation
facility once the construction phase has been completed.
AEP is the construction agent for Katco, and is responsible for completing
construction by December 31, 2003, subject to unforeseen events beyond AEP's
control.
In the event the project is terminated before completion of construction, AEP
has the option to either purchase the facility for 100% of project costs or
terminate the project and make a payment to Katco for 89.9% of project costs.
The operating lease between Katco and AEP commences on the commercial operation
date of the facility and continues until November 2006. The lease contains
extension options subject to the approval of Katco, and if all extension options
were exercised, the total term of the lease would be 30 years. AEP's lease
payments to Katco are sufficient for Katco to make required debt payments and
provide a return to the investors of Katco. At the end of each lease term, AEP
may renew the lease at fair market value subject to Katco's approval, purchase
the facility at its original construction cost, or sell the facility, on behalf
of Katco, to an independent third party. If the facility is sold and the
proceeds from the sale are insufficient to repay Katco, AEP may be required to
make a payment to Katco for the difference between the proceeds from the sale
and the obligations of Katco, up to 82% of the project's cost. AEP has
guaranteed a portion of the obligations of its subsidiaries to Katco during the
construction and post-construction periods.
As of December 31, 2002, project costs subject to these agreements totaled $360
million, and total costs for the completed facility are expected to be
approximately $510 million. For the 30-year extended lease term, the lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently
as market interest rates increase, the payments under this operating lease will
also increase. Annual payments of approximately $12 million represent future
minimum payments during the initial term calculated using the indexed LIBOR rate
(1.38% at December 31, 2002). The Power Generation Facility collateralizes the
debt obligation of Katco. AEP's maximum exposure to loss as a result of its
involvement with Katco is 100% during the construction phase and up to 82% once
the construction is completed. Maximum loss is deemed to be remote due to the
collateralization.
It is reasonably possible that AEP will consolidate Katco in the third quarter
of 2003, as a result of the issuance of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP
would record the assets, liabilities, depreciation expense, minority interest
and debt interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.
The lease payments and the guarantee of construction commitments are included in
the Other Commercial Commitments table below.
Minority Interest in Finance Subsidiary
- ---------------------------------------
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne)
and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated
subsidiary of AEP that was capitalized with the assets of Houston Pipe Line
Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million
of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary
and parent of SubOne) preferred stock, that is convertible into AEP common stock
at market price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an unconditional
obligation to fund $83 million from SubOne and $750 million from Steelhead
Investors LLC ("Steelhead" - non-controlling preferred member interest). As
managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and has a capital structure of $750 million of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to
limit its risk associated with Houston Pipe Line Company and Louisiana
Intrastate Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead receives a
quarterly preferred return equal to an adjusted floating reference rate (4.784%
and 4.413% for the quarters ended December 31, 2002 and 2001, respectively).
Caddis has the right to redeem Steelhead's interest at any time.
The $750 million invested in Caddis by Steelhead was loaned to SubOne. This
intercompany loan to SubOne is due August 2006, and is supported by the natural
gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4
million of preferred stock in AEP Gas Holding. The preferred stock is
convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if SubOne were to reduce its loan with Caddis by $225 million. The credit
agreement between Caddis and SubOne contains covenants that restrict certain
incremental liens and indebtedness, asset sales, investments, acquisitions, and
distributions. The credit agreement also contains covenants that impose minimum
financial ratios. Non-performance of these covenants may result in an event of
default under the credit agreement. Through December 31, 2002, we have complied
with the covenants contained in the credit agreement. In addition, a default
under any other agreement or instrument relating to AEP and certain
subsidiaries' debt outstanding in excess of $50 million is an event of default
under the credit agreement.
The initial period of Steelhead's investment in Caddis is through August 2006.
At the end of the initial period, Caddis will either reset Steelhead's return
rate, re-market Steelhead's interests to new investors, redeem Steelhead's
interests, in whole or in part including accrued return, or liquidate Caddis in
accordance with the provisions of applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events including a default in the payment of the preferred
return, Steelhead's rights include: forcing a liquidation of Caddis and acting
as the liquidator, and requiring the conversion of the AEP Gas Holding preferred
stock into AEP common stock. If Steelhead exercised its rights to force Caddis
to liquidate under these conditions, then AEP would evaluate whether to
refinance at that time or relinquish the assets that support the intercompany
loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are separate and
legally distinct from AEP. The results of operations, cash flows and financial
position of Caddis and SubOne are consolidated with AEP for financial reporting
purposes. Steelhead's investment in Caddis and payments made to Steelhead from
Caddis are currently reported on AEP's income statement and balance sheet as
Minority Interest in Finance Subsidiary.
AEP's maximum exposure to loss as a result of its involvement with Steelhead is
$321.4 million of preferred stock, $83 million under the subscription agreement
to Caddis for any losses incurred by Caddis and the cash reserve fund balance of
$34 million (as of December 31, 2002) due Caddis for default under the
intercompany loan agreement. AEP can reduce its maximum exposure related to the
preferred stock by a reduction of $225 million of the intercompany loan.
As of December 31, 2002, management is continuing to review the application of
FIN 46 as it relates to the Steelhead transaction.
AEP Credit
- ----------
AEP Credit entered into a sale of receivables agreement with a group of banks
and commercial paper conduits. Under the sale of receivables agreement, which
expires May 28, 2003, AEP Credit sells an interest in the receivables it
acquires to the commercial paper conduits and banks and receives cash. This
transaction constitutes a sale of receivables in accordance with SFAS 140
allowing the receivables to be taken off of AEP Credit's balance sheet and
allowing AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities in
accordance with GAAP. We continue to service the receivables. This off-balance
sheet transaction was entered into to allow AEP Credit to repay its outstanding
debt obligations, continue to purchase the AEP operating companies' receivables,
and accelerate its cash collections.
At December 31, 2002, the sale of receivables agreement provided the banks and
commercial paper conduits would purchase a maximum of $600 million of
receivables from AEP Credit, of which $454 million was outstanding. As
collections from receivables sold occur and are remitted, the outstanding
balance for sold receivables is reduced and as new receivables are sold, the
outstanding balance of sold receivables increases. All of the receivables sold
represented affiliate receivables. The commitment's new term under the sale of
receivables agreement will remain at $600 million until May 28, 2003. AEP Credit
maintains a retained interest in the receivables sold and this interest is
pledged as collateral for the collection of the receivables sold. The fair value
of the retained interest is based on book value due to the short-term nature of
the accounts receivables less an allowance for anticipated uncollectible
accounts.
See Note 23 "Lines of Credit and Sale of Receivables" for further disclosure.
Gavin Plant's flue gas desulfurization system (Gavin Scrubber)
- -------------------------------------------------------------
OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated
unconsolidated special purpose entity. JMG has a capital structure of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from pollution control bonds and other bonds. JMG owns the Gavin
Scrubber and leases it to OPCo. The lease is accounted for as an operating lease
with the payment obligations included in the lease footnote. Payments under the
operating lease are based on JMG's cost of financing (both debt and equity) and
include an amortization component plus the cost of administration. Neither OPCo
nor AEP has an ownership interest in JMG and does not guarantee JMG's debt.
At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial
15-year lease term is non-cancelable. At the end of the initial term, OPCo can
renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or
sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition
cost, OPCo must pay the difference to JMG.
The use of JMG allows OPCo to enter into an operating lease while keeping the
tax benefits otherwise associated with a capital lease. As of December 31, 2002,
unless the structure of this arrangement is changed, it is reasonably possible
that AEP and OPCo will consolidate JMG in the third quarter of 2003 as a result
of the issuance of FIN 46. Upon consolidation, AEP and OPCo would record the
assets, liabilities, depreciation expense, minority interest and debt interest
expense of JMG. AEP and OPCo would eliminate operating lease expense. AEP's and
OPCo's maximum exposure to loss as a result of their involvement with JMG is
approximately $560 million of outstanding debt and equity of JMG as of December
31, 2002.
Rockport Plant Unit 2
- ---------------------
AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.
Summary Obligation Information
The contractual obligations of AEP and its subsidiaries include amounts reported
on the Consolidated Balance Sheets and other obligations disclosed in the
footnotes. The following table summarizes AEP's contractual cash obligations at
December 31, 2002:
Payments Due by Period
(in millions)
Contractual Cash Obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total
- ---------------------------- ---------------- --------- --------- ------------- -----
Long-term Debt $1,633 $1,817 $2,316 $4,354 $10,120
Short-term Debt 3,164 - - - 3,164
Equity Unit Senior Notes - - 376 - 376
Trust Preferred Securities - - - 321 321
Minority Interest In Finance
Subsidiary (a) - - 759 - 759
Preferred Stock Subject to
Mandatory Redemption - - - 84 84
Capital Lease Obligations 70 90 50 18 228
Unconditional Purchase
Obligations (b) 1,405 1,810 989 1,513 5,717
Noncancellable Operating Leases 305 523 479 2,462 3,769
------ ------ ------ ------ -------
Total Contractual
Cash Obligations $6,577 $4,240 $4,969 $8,752 $24,538
====== ====== ====== ====== =======
(a) The initial period of the preferred interest is through August 2006. At the
end of the initial period, the preferred rate may be reset, the preferred
member interests may be re-marketed to new investors, the preferred member
interests may be redeemed, in whole or in part including accrued return, or
the preferred member interest may be liquidated.
(b) Represents contractual obligations to purchase coal and natural gas as fuel
for electric generation along with related transportation of the fuel.
For the subsidiary registrants, please see each registrant's schedules of
capitalization and long-term debt included with each registrants' financial
statements in sections B through K for the timing of debt payment obligations
and the lease footnote (Note 22) in section L for the timing of rent payments.
The special purpose entities (SPE), described under "Off-Balance Sheet and
Minority Interest Arrangements" above, have been employed for some of the
contractual cash obligations reported in the above table. The lease of Rockport
Plant Unit 2 and the Gavin Scrubber, the permanent financing of HPL, and the
sale of accounts receivable all use SPEs. Neither AEP nor any AEP related
parties have an ownership interest in the SPE. AEP does not guarantee the debt
of these entities. These SPEs are not consolidated in AEP's or the subsidiaries'
financial statements in accordance with GAAP. As a result, neither the assets
nor the debt of the SPE are included on AEP's Consolidated Balance Sheets. The
future cash obligations payable to the SPEs are included in the above table.
In addition to the amounts disclosed in the contractual cash obligations table
above, AEP and its subsidiaries make commitments in the normal course of
business. These commitments include standby letters of credit, guarantees for
the payment of obligation performance bonds, and other commitments. AEP's
commitments outstanding at December 31, 2002 under these agreements are
summarized in the table below:
Amount of Commitment Expiration Per Period
(in millions)
Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total
- ---------------------------- ---------------- --------- --------- ------------- -----
Standby Letters of Credit (a) $ 125 $ 1 $ - $ 40 $ 166
Guarantees of the Performance
of Ooutside Parties (b) 13 17 325 137 492
Guarantess of Our Performance 1,159 2 82 9 1,252
Construction of Generating and
Transmission Facilities for
Third Parties (c) 671 83 47 67 868
Other Commercial
Commitments (d) 14 53 11 - 78
------ ---- ---- ---- ------
Total Commercial Commitments $1,982 $156 $465 $253 $2,856
====== ==== ==== ==== ======
(a) AEP has standby letters of credit to third parties. These letters of credit
cover gas and electricity trading contracts, various construction contracts
and credit enhancement for issued bonds. All of these letters of credit
were issued at a subsidiary level of AEP in the subsidiaries' ordinary
course of business. The maximum future payments of these letters of credit
are $166 million with maturities ranging from January 2003 to December
2007. There is no liability recorded for these letters of credit in
accordance with FIN 45. Since AEP is the parent to all these subsidiaries,
it holds all assets of the subsidiary as collateral. There is no recourse
to third parties in the event these letters of credit are drawn.
(b) These amounts are the balances drawn, not the maximum guarantee disclosed in
Note 10.
(c) As construction agent for third party owners of power plants and
transmission facilities, AEP has committed by contract terms to complete
construction by dates specified in the contracts. Should AEP default on
these obligations, financial payments could be up to 100% of contract
value (amount shown in table) or other remedies required by contract terms.
(d) Represents estimated future payments for power to be generated at facilities
under construction.
With the exceptions of SWEPCo's guarantee of an unaffiliated mine operator's
obligations (payable upon their default) of $148 million at December 31, 2002,
and OPCo's obligations under a power purchase agreement of $14 million each year
in 2003 through 2005, the obligations in the above table are commitments of AEP
and its non-registrant subsidiaries.
OPCo has entered into a 30-year power purchase agreement for electricity
pro-duced by an unaffiliated entity's three-unit natural gas fired plant. The
plant was completed in 2002 and the agreement will terminate in 2032. Under the
terms of the agreement, OPCo has the option to run the plant until December 31,
2005 taking 100% of the power generated and making monthly capacity payments.
The capacity payments are fixed through December 2005 at $1.2 million per month.
For the remainder of the 30 year contract term, OPCo will pay the variable costs
to generate the electricity it purchases which could be up to 20% of the plant's
capacity. The estimated fixed payments are included in the Other Commercial
Commitments table shown above.
Expenditures for domestic electric utility construction are estimated to be $4
billion for the next three years. Approximately 90% of those construction
expenditures are expected to be financed by internally generated funds.
Construction expenditures for certain registrant subsidiaries for the next three
years are:
Construction
Projected Expenditures
Construction Financed with
Expenditures Internal Funds
------------ --------------
(in millions)
APCo $1,005 70%
I&M 601 90
OPCo 733 100
SWEPCo 351 100
TCC 419 100
APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Certificates have been issued by both the WVPSC and the Virginia
SCC authorizing construction and operation of the line. On December 31, 2002,
the United States Forest Service issued a final environmental impact statement
and record of decision to allow the use of federal lands in the Jefferson
National Forest for construction of a portion of the line. APCo expects
additional state and federal permits to be issued in the first half of 2003.
Through December 31, 2002, APCo has invested approximately $51 million in this
effort. The line is estimated to cost $287 million including amounts spent to
date with completion in 2006. If the required permits are not obtained and the
line is not constructed, the $51 million investment would be written off
adversely affecting future results of operations and cash flows.
Pension Plans
- -------------
AEP maintains qualified defined benefit pension plans (Qualified Plans), which
cover substantially all non-union and certain union associates, and unfunded
excess plans to provide benefits in excess of amounts permitted to be paid under
the provisions of the tax law to participants in the Qualified Plans.
Additionally, AEP has entered into individual retirement agreements with certain
current and retired executives that provide additional retirement benefits.
AEP's pension income for all pension plans approximated $69 million and $44
million for the years ended December 31, 2001 and December 31, 2002,
respectively, and is calculated based upon a number of actuarial assumptions,
including an expected long-term rate of return on the Qualified Plans' assets of
9%. In developing the expected long-term rate of return assumption, AEP
evaluated input from actuaries and investment consultants, including their
reviews of asset class return expectations as well as long-term inflation
assumptions. Projected returns by such actuaries and consultants are based on
broad equity and bond indices. AEP also considered historical returns of the
investment markets as well as AEP's 10-year average return (for the period ended
2002) of 8.8%. AEP anticipates that the investment managers will continue to
generate long-term returns of at least 9.0%. The expected long-term rate of
return on the Qualified Plans' assets is based on an asset allocation assumption
of 70% with equity managers, with an expected long-term rate of return of 10.5%,
and 28% with fixed income managers, with an expected long-term rate of return of
6%, and 2% in cash and short term investments with an expected rate of return of
3%. Because of market fluctuation, the actual asset allocation as of December
31, 2002 was 67% with equity managers and 32% with fixed income managers and 1%
in cash. AEP believes, however, that the long-term asset allocation on average
will approximate 70% with equity managers, 28% with fixed income managers and
the remaining 2% in cash. AEP regularly reviews the actual asset allocation and
periodically rebalances the investments to our targeted allocation when
considered appropriate. AEP continues to believe that 9.0% is a reasonable
long-term rate of return on the Qualified Plans' assets, despite the recent
market downturn in which the Qualified Plans' assets had a loss of 11.2% for the
twelve months ended December 31, 2002. AEP will continue to evaluate the
actuarial assumptions, including the expected rate of return, at least annually,
and will adjust as necessary.
AEP bases its determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded. As of December 31, 2002 AEP had
cumulative losses of approximately $879 million which remain to be recognized in
the calculation of the market-related value of assets. These unrecognized net
actuarial losses result in increases in 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 AEP utilizes for determining future pension obligations
is based on a review of long-term bonds that receive one of the two highest
ratings given by a recognized rating agency. The discount rate determined on
this basis has decreased from 7.25% at December 31, 2001 to 6.75% at December
31, 2002. Due to the effect of the unrecognized actuarial losses and based on an
expected rate of return on the Qualified Plans' assets of 9.0%, a discount rate
of 6.75% and various other assumptions, AEP estimates that the pension expense
for all pension plans will approximate $2 million, $46 million and $97 million
in 2003, 2004 and 2005, respectively. Future actual pension expense will depend
on future investment performance, changes in future discount rates and various
other factors related to the populations participating in the pension plans.
Lowering the expected long-term rate of return on the Qualified Plans' assets by
..5% (from 9.0% to 8.5%) would have reduced pension income for 2002 by
approximately $19 million. Lowering the discount rate by 0.5% would have reduced
pension income for 2002 by approximately $8 million.
The value of the Qualified Plans' assets has decreased from $3.438 billion at
December 31, 2001 to $2.795 billion at December 31, 2002. The Qualified Plans
paid out $272 million in benefits to plan participants during 2002 (nonqualified
plans paid out $6 million in benefits). The investment returns and declining
discount rates have changed the status of the Qualified Plans from overfunded
(plan assets in excess of projected benefit obligations) by $146 million at
December 31, 2001 to an underfunded position (plan assets are less than
projected benefit obligations) of $788 million at December 31, 2002. Due to the
Qualified Plans currently being underfunded, AEP recorded a charge to Other
Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of
$315 million, offset by a Minimum Pension Liability of $662 million and a
reduction to prepaid costs and intangible assets of $238 million. The charge to
OCI does not affect earnings or cash flow. AEP is in full compliance with all
regulations governing such plans including all Employee Retirement Income
Security Act of 1974 laws. Because of the recent reductions in the funded status
of the Qualified Plans, AEP expects to make cash contributions to the Qualified
Plans of approximately $66 million in 2003 increasing to approximately $108
million per year by 2005.
Critical Accounting Policies
In the ordinary course of business, AEP and its registrant subsidiaries have
made a number of estimates and assumptions relating to the reporting of results
of operations and financial condition in the preparation of their financial
statements in conformity with accounting principles generally accepted in the
United States of America. Actual results could differ significantly from those
estimates under different assumptions and conditions. They 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 - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo,
TCC, TNC and SWEPCo) reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide for refunds to customers
that have not yet been made.
When regulatory assets are probable of recovery through regulated rates, they
record them as assets on the balance sheet. They test for probability of
recovery whenever new events occur, for example, issuance of a regulatory
commission order or passage of new legislation. If they determine that recovery
of a regulatory asset is no longer probable, they write-off that regulatory
asset as a charge against earnings. A write-off of 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. Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts, excluding
wellhead purchases of natural gas, swaps and options for the domestic pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair value during the period are recognized currently in the results of
operations, appropriately discounted and net of applicable credit and liquidity
reserves.
Energy Marketing and Trading Activities -In 2000, 2001 and throughout the
majority of 2002, AEP engaged in broad non-regulated wholesale electricity,
natural gas and other commodity marketing and trading transactions (trading
activities). AEP's trading activities involved the purchase and sale of energy
under forward contracts at fixed and variable prices and the buying and selling
of financial energy contracts which include exchange traded futures and options
and over-the-counter options and swaps. We used the mark-to-market method of
accounting for trading activities as required by EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains
and losses from settlements of forward trading contracts are recorded net in
revenues. For energy contracts not yet settled, whether physical or financial,
changes in fair value are recorded net as revenues. Such fair value changes are
referred to as unrealized gains and losses from mark-to-market valuations. When
positions are settled and gains and losses are realized, the previously recorded
unrealized gains and losses from mark-to-market valuations are reversed.
Unrealized mark-to-market gains and losses are included in the Balance Sheets as
"Energy Trading and Derivative Contracts." In October 2002, management announced
plans to focus on wholesale markets where we own assets. A portion of the
revenues and costs associated with AEP's wholesale electricity trading
activities is allocated to TCC, SWEPCo, PSO and TNC and to members of the AEP
Power Pool (APCo, CSPCo, I&M, KPCo and OPCo); however, TCC, SWEPCo, PSO and TNC
are only allocated a portion of the forward transactions.
AEP's cost-based rate-regulated electric public utility companies (I&M, KPCo,
PSO, and a portion of TNC and SWEPCo) defer, as regulatory liabilities
(unrealized gains) or regulatory assets (unrealized losses), changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area. AEP's traditional marketing area is up to two transmission
systems from the AEP service territory. For contracts which are outside of AEP's
traditional marketing area, the change in fair value is included in nonoperating
income on a net basis.
The majority of trading activities represent physical forward contracts that are
typically settled by entering into offsetting contracts. An example of our
energy trading activities is when, in January, we enter into a forward sales
contract to deliver energy in July. At the end of each month until the contract
settles in July, we would record any difference between the contract price and
the market price as an unrealized gain or loss in revenues. In July when the
contract settles, we would realize a gain or loss in cash and reverse to
revenues the previously recorded cumulative unrealized gain or loss. Prior to
settlement, the change in the fair value of physical forward sale and purchase
contracts is included in revenues on a net basis. Upon settlement of a forward
trading contract, the amount realized for a sales contract and the realized cost
for a purchase contract are included on a net basis in revenues with the prior
change in unrealized fair value reversed out of revenues.
For I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles
the total gain or loss is realized in cash and the impact on the income
statement depends on whether the contract's delivery points are within or
outside of AEP's traditional marketing area. For contracts with delivery points
in AEP's traditional marketing area, the total gain or loss realized in cash for
sales and the cost of purchased energy are included in revenues on a net basis.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts in AEP's traditional marketing area are deferred as
regulatory liabilities (gains) or regulatory assets (losses). For contracts with
delivery points outside of AEP's traditional marketing area only the difference
between the accumulated unrealized net gains or losses recorded in prior periods
and the cash proceeds is recognized in the income statement as nonoperating
income. Prior to settlement, changes in the fair value of physical forward sale
and purchase contracts with delivery points outside of AEP's traditional
marketing area are included in nonoperating income on a net basis. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities as appropriate.
For APCo, CSPCo and OPCo, depending on whether the delivery point for the
electricity is in AEP's traditional marketing area or not determines where the
contract is reported in the income statement. Physical forward trading sale and
purchase contracts with delivery points in AEP's traditional marketing area are
included in revenues on a net basis. Prior to settlement, changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area are also included in revenues on a net basis. Physical forward
sale and purchase contracts for delivery outside of AEP's traditional marketing
area are included in nonoperating income when the contract settles. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts with delivery points outside of AEP's traditional marketing area are
included in nonoperating income on a net basis.
Continuing with the above example for AEP, APCo, CSPCo, OPCo, TCC, and a portion
of TNC and SWEPCo, assume that later in January or sometime in February through
July we enter into an offsetting forward contract to buy energy in July. If we
do nothing else with these contracts until settlement in July and if the
commodity type, volumes, delivery point, schedule and other key terms match,
then the difference between the sale price and the purchase price represents a
fixed value to be realized when the contracts settle in July. Mark-to-market
accounting for these contracts from this point forward will have no further
impact on operating results but has an offsetting and equal effect on trading
contract assets and liabilities. If the sale and purchase contracts do not match
exactly as to commodity type, volumes, delivery point, schedule and other key
terms, then there could be continuing mark-to-market effects on revenues from
recording additional changes in fair values using MTM accounting.
For AEP, the trading of energy options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in revenues until the contracts settle. When these contracts
settle, we record the net proceeds in revenues and reverse to revenues the prior
cumulative unrealized net gain or loss. APCo, CSPCo, I&M, KPCo and OPCo also
have financial transactions, but record the unrealized gains and losses, as well
as the net proceeds upon settlement, in nonoperating income.
The fair values of open short-term trading contracts are based on exchange
prices and broker quotes. We mark-to-market open long-term trading contracts
based primarily on valuation models that estimate future energy prices based on
existing market and broker quotes and supply and demand market data and
assumptions. The fair values determined are reduced by the appropriate valuation
adjustments for items such as discounting, liquidity and credit quality. Credit
risk is the risk that the counterparty to the contract will fail to perform or
fail to pay amounts due to AEP. Liquidity risk represents the risk that
imperfections in the market will cause the price to be less than or more than
what the price should be based purely on supply and demand. There are inherent
risks related to the underlying assumptions in models used to fair value open
long-term trading contracts. We have independent controls to evaluate the
reasonableness of our valuation models. However, energy markets, especially
electricity markets, are imperfect and volatile. Unforeseen events can and will
cause reasonable price curves to differ from actual prices throughout a
contract's term and at the time contracts settle. Therefore, there could be
significant adverse or favorable effects on future results of operations and
cash flows if market prices are not consistent with AEP's approach at estimating
current market consensus for forward prices in the current period. This is
particularly true for long-term contracts.
AEP applies MTM accounting to derivatives that are not trading contracts in
accordance with generally accepted accounting principles. Derivatives are
contracts whose value is derived from the market value of an underlying
commodity.
Volatility in energy commodities markets affects the fair values of all of our
open trading and derivative contracts exposing us to market risk and causing our
results of operations to be subject to volatility. See Note 17, "Risk
Management, Financial Instruments and Derivatives" for a discussion of the
policies and procedures used to manage our exposure to market and other risks
from trading activities.
Given the previously discussed reduction in AEP's trading activities, the impact
of mark-to-market accounting on our financial statements is expected to decline
in future periods.
Long-Lived Assets
- -----------------
Long-lived assets, including fixed assets and intangibles, are evaluated
periodically for impairment whenever events or changes in circumstances indicate
that the carrying amount of any such assets may not be recoverable. If the sum
of the undiscounted cash flows is less than the carrying value, we recognize an
impairment loss, measured as the amount by which the carrying value exceeds the
fair value of the asset. The estimate of cash flow is based upon, among other
things, certain assumptions about expected future operating performance. Our
estimates of undiscounted cash flow may differ from actual cash flow due to,
among other things, technological changes, economic conditions, changes to its
business model or changes in its operating performance.
Pension Benefits
- ----------------
AEP sponsors pension and other retirement plans in various forms covering
substantially all employees who meet eligibility requirements. Several
statistical and other factors which attempt to anticipate future events are used
in calculating the expense and liability related to the plans. These factors
include assumptions about the discount rate, expected return on plan assets and
rate of future compensation increases as determined by management, within
certain guidelines. In addition, AEP's actuarial consultants also use subjective
factors such as withdrawal and mortality rates to estimate these factors. The
actuarial assumptions used may differ materially from actual results due to
changing market and economic conditions, higher or lower withdrawal rates or
longer or shorter life spans of participants. These differences may result in a
significant impact to the amount of pension expense recorded.
New Accounting Pronouncements
- -----------------------------
See Note 1 to the consolidated financial statements for a discussion
of significant accounting policies and new accounting pronouncements.
Market Risks
As a major power producer and marketer of wholesale electricity and natural gas,
we have certain market risks inherent in our business activities. These risks
include commodity price risk, interest rate risk, foreign exchange risk and
credit risk. They represent the risk of loss that may impact us due to changes
in the underlying market prices or rates.
Policies and procedures have been established to identify, assess, and manage
market risk exposures in our day to day operations. Our risk policies have been
reviewed with the Board of Directors, approved by a Risk Executive Committee and
administered by a Chief Risk Officer. The Risk Executive Committee establishes
risk limits, approves risk policies, assigns responsibilities regarding the
oversight and management of risk and monitors risk levels. This committee
receives daily, weekly, and monthly reports regarding compliance with policies,
limits and procedures. The committee meets monthly and consists of the Chief
Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.
We use a risk measurement model which calculates Value at Risk (VaR) to measure
our commodity price risk in the trading portfolio. The VaR is based on the
variance - covariance method using historical prices to estimate volatilities
and correlations and assuming a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at December 31, 2002 a near term typical
change in commodity prices is not expected to have a material effect on our
results of operations, cash flows or financial condition. The following table
shows the high, average, and low market risk as measured by VaR at:
December 31,
-----------
2002 2001
---- ----
High Average Low High Average Low
---- ------- --- ---- ------- ---
(in millions)
AEP $24 $12 $4 $28 $14 $5
APCo 4 1 - 4 1 -
CSPCo 3 1 - 2 1 -
I&M 3 1 - 3 1 -
KPCo 1 - - 1 - -
OPCo 4 1 - 3 1 -
PSO - - - 2 1 -
SWEPCo - - - 3 1 -
TCC - - - 3 1 -
TNC - - - 1 1 -
After the October announcement of our strategy to reduce trading activity, the
related VaRs were substantially reduced. The average AEP trading VaR for the
fourth quarter 2002 was $7 million as compared to $13 million for fourth quarter
2001. In 2003 we will continue to adjust our VaR limit structure commensurate
with our anticipated level of trading activity.
We also utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $527 million at
December 31, 2002 and $673 million at December 31, 2001. However, since we would
not expect to liquidate our entire debt portfolio in a one year holding period,
a near term change in interest rates should not materially affect results of
operations or consolidated financial position.
The following table shows the potential loss in fair value as measured by VaR
allocated to the AEP registrant subsidiaries based upon debt outstanding:
VaR for Registrant Subsidiaries:
December 31,
-----------
2002 2001
---- ----
(in millions)
Company
AEGCo $ 3 $5
APCo 87 100
CSPCo 33 60
I&M 85 86
KPCo 30 16
OPCo 34 59
PSO 70 17
SWEPCo 70 36
TCC 65 80
TNC 5 20
AEGCo is not exposed to risk from changes in interest rates on short-term and
long-term borrowings used to finance operations since financing costs are
recovered through the unit power agreements.
AEP is exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in
the ERCOT area of Texas (effective January 1, 2002 for TCC and TNC) or frozen by
settlement agreements in Michigan and West Virginia or capped in Indiana. To the
extent the fuel supply of the generating units in these states is not under
fixed price long-term contracts AEP is subject to market price risk. AEP
continues to be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree other commodities and as a result we are
subject to price risk. The amount of risk taken by the traders is controlled by
the management of the trading operations and the Company's Chief Risk Officer
and his staff. When the risk from trading activities exceeds certain
pre-determined limits, the positions are modified or hedged to reduce the risk
to be within the limits unless specifically approved by the Risk Executive
Committee.
We employ fair value hedges, cash flow hedges and swaps to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on certain power
trading transactions denominated in foreign currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate
fluctuations in debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.
Credit Risk
AEP limits credit risk by extending unsecured credit to entities based on
internal ratings. In addition, AEP uses Moody's Investor Service, Standard and
Poor's and qualitative and quantitative data to independently assess the
financial health of counterparties on an ongoing basis. This data, in
conjunction with the ratings information, is used to determine appropriate risk
parameters. AEP also requires cash deposits, letters of credit and
parental/affiliate guarantees as security from counterparties depending upon
credit quality in our normal course of business.
We trade electricity and gas contracts with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty is not material to our financial
condition at December 31, 2002. At December 31, 2002 approximately 7% of our
exposure was below investment grade as expressed in terms of net MTM assets. Net
MTM assets represents the aggregate difference between the forward market price
for the remaining term of the contract and the contractual price per
counterparty. As of December 31, 2002, the following table approximates
counterparty credit quality and exposure for AEP based on netting across AEP
entities, commodities and instruments:
Futures,
Forward and
Counterparty Swap
Credit Quality: Contracts Options Total
- -------------- ------- ------- ------
(in millions)
AAA/Exchanges $ 26 $ 2 $ 28
AA 307 33 340
A 448 26 474
BBB 700 101 801
Below Investment
Grade 107 11 118
--------- ----- --------
Total $ 1,588 $173 $1,761
======= ==== ======
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
We enter into transactions for electricity and natural gas as part of wholesale
trading operations. Electric and gas transactions are executed over the counter
with counterparties or through brokers. Gas transactions are also executed
through brokerage accounts with brokers who are registered with the Commodity
Futures Trading Commission. Brokers and counterparties require cash or cash
related instruments to be deposited on these transactions as margin against open
positions. The combined margin deposits at December 31, 2002 and 2001 were $109
million and $55 million, respectively. These margin accounts are restricted and
therefore are not included in Cash and Cash Equivalents on the Balance Sheets.
We can be subject to further margin requirements should related commodity prices
change.
We recognize the net change in the fair value of all open trading contracts, in
accordance with generally accepted accounting principles and include the net
change in mark-to-market amounts on a net discounted basis in revenues. The
marking-to-market of open trading contracts contributed an unrealized $180
million to revenues in 2002. The mark-to-market fair values of open short-term
trading contracts are based on exchange prices and broker quotes. The fair value
of open long-term trading contracts are based mainly on internally developed
valuation models. The gross value is present valued and reduced by appropriate
valuation adjustments for counterparty credit risks and liquidity risk to arrive
at fair value. The models are derived from internally assessed market prices
with the exception of the NYMEX gas curve, where we use daily settled prices.
Forward price curves are developed for inclusion in the model based on broker
quotes and other available market data. The liquid portion of these curves are
validated on a regular basis by the middle-office through the market data.
Illiquid portions of the curves are validated through a review of the underlying
market assumptions and variables for consistency and reasonableness. The end of
the month liquidity reserve is based on the difference in price between the
price curve and the bid price if we have a long position and the price curve and
the ask price if we have a short position. This provides for a more accurate
valuation of energy contracts.
The use of these models to fair value open trading contracts has inherent risks
relating to the underlying assumptions employed by such models. Independent
controls are in place to evaluate the reasonableness of the price curve models.
Significant adverse or favorable effects on future results of operations and
cash flows could occur if market prices, at the time of settlement, do not
correlate with our interally developed price models.
The effect on the Statements of Operations of marking to market open electricity
trading contracts in AEP's regulated jurisdictions, specifically I&M, KPCo, PSO
and a portion of SWEPCO, is deferred as regulatory assets (losses) or
liabilities (gains) since these transactions are included in cost of service on
a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and
losses from trading are reported as assets or liabilities.
The following table shows net revenues (revenues less fuel and purchased energy
expense) and their relationship to the mark-to-market revenues (the change in
fair value of open trading contracts).
December 31,
-----------
2002 2001 2000
---- ---- ----
(in millions)
Revenues
(including
Mark- To-
Market
Adjustment) $14,555 $12,767 $11,113
Fuel and
Purchased
Energy
Expense 6,307 4,944 3,880
------- ------- -------
Net Revenues $ 8,248 $ 7,823 $ 7,233
======= ======= =======
Mark-to-Market
Revenues $180 $207 $187
=== ==== ====
Percentage of
Net Revenues
Represented by
Mark-to-Market
On Open
Trading Positions 2% 3% 3%
== == ==
The following tables analyze the changes in fair values of trading assets and
liabilities. The first table "Net Fair Value of Mark-to-Market Energy Trading
and Derivative Contracts" shows how the net fair value of energy trading
contracts was derived from the amounts included in the Consolidated Balance
Sheets line item "Energy Trading and Derivative Contracts." The next table
"Mark-to-Market Energy Trading and Derivative Contracts" disaggregates realized
and unrealized changes in fair value; identifies changes in fair value as a
result of changes in valuation methodologies; and reconciles the net fair value
of energy trading contracts and related derivatives at December 31, 2001 of $448
million to December 31, 2002 of $250 million. Contracts realized/settled during
the period include both sales and purchase contracts. The third table
"Mark-to-Market Energy Trading and Derivative Contract Maturities" shows
exposures to changes in fair values and realization periods over time for each
method used to determine fair value.
Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts - AEP
December 31
----------------------
2002 2001
---- ----
(in millions)
Energy Trading and Derivative Contracts:
Current Asset $1,046 $ 2,125
Long-term Asset 824 795
Current Liability (1,147) (1,877)
Long-term Liability (484) (603)
------ -------
Net Fair Value of Energy Trading and Derivative Contracts 239 440
Non-trading related derivative liabilities 11* -
Assets held for sale (CitiPower) - 8
------ -------
Net Fair Value of Energy Trading and Derivative Contracts $ 250 $ 448
====== =======
* Excludes $6 million Loss recorded in an equity investment.
The above net fair value of energy trading and derivative contracts includes
$180 million at December 31, 2002, in unrealized mark-to-market gains that are
recognized in the Consolidated Statements of Operations at December 31, 2002.
Mark-to-Market Energy Trading and Derivative Contracts - AEP
Total
-----
(in millions)
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2001 $ 448
(Gain) Loss from Contracts Realized/Settled During the Period (182) (a)
Fair Value of New Open Contracts When Entered Into During the Period 68 (b)
Net Option Premiums Paid/(Received) (130) (c)
Change in fair value due to Methodology Changes 1 (d)
Change in Market Value of Energy Trading Contracts
Allocated to Regulated Jurisdictions (2) (e)
Changes in Market Value of Contracts 47 (f)
-----
Net Fair Value of Energy Trading and Derivative Contracts
at December 31, 2002 $ 250
=====
Mark-to-Market Energy Trading and Derivative Contracts - Registrant Subsidiaries
APCo CSPCo I&M
---- ----- ---
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 75,701 $48,449 $ 61,345
(Gain) Loss from Contracts
Realized/Settled During the Period (a) (19,143) (13,812) (9,611)
Change in Fair Value Due To
Methodology Changes (d) 350 228 247
Changes in Fair Market Value of Energy
Trading Contracts Allocated To
Regulated Jurisdictions (e) - - 1,502
Fair Value Of New Open Contracts
When Entered Into during The Period (b) 10,865 7,039 2,774
Net Option Premium Payments (c) (1,797) (1,208) (1,292)
Changes In Market Value Of Contracts (f) 30,876 24,421 15,896
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at December 31, 2002 (g) $ 96,852 $65,117 $ 70,861
======== ======= ========
KPCo OPCo PSO
---- ---- ---
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $12,729 $ 65,446 $ 2,434
(Gain) Loss From Contracts
Realized/Settled During Period (a) 1,153 (18,337) 6,476
Change in Fair Value Due To
Methodology Changes (d) 90 311 32
Changes In Fair Market Value Of Energy
Trading Contracts Allocated To
Regulated Jurisdiction (e) 5,136 - (5,397)
Fair Value of New Open Contracts
When Entered Into During Period (b) 1,013 18,443 -
Net Option Premium Payments (c) (464) (1,603) -
Changes In Market Value Of Contracts (f) 5,341 29,846 -
------- -------- -------
Net Fair Value of Energy Trading
Contracts at December 31, 2002 (g) $24,998 $ 94,106 $ 3,545
======= ======== =======
SWEPCo TCC TNC
------ --- ---
Net Fair Value of Energy Trading
Contracts at December 31, 2001 $ 2,900 $ 3,857 $ 915
(Gain) Loss From Contracts
Realized/Settled During The Period (a) 6,971 7,138 2,413
Change in Fair Value Due To
Methodology Changes (d) 36 42 12
Changes In Fair Market Value Of Energy
Trading Contracts Allocated To
Regulated jurisdiction (e) (2,485) - (336)
Fair Value Of New Open Contracts
When Entered Into During The Period (b) 428 1,919 1,627
Net Option Premium Payments (c) - - -
Changes In Market Value Of Contracts (f) (3,800) (7,542) (2,588)
------- ------- -------
Net Fair Value of Energy Trading
Contracts at December 31, 2002 (g) $ 4,050 $ 5,414 $ 2,043
======= ======= =======
(a) "(Gain) Loss from Contracts Realized/Settled During the Period" include
realized gains from energy trading contracts and related derivatives that
settled during 2002 that were entered into prior to 2002. (b) The "Fair Value of
New Open Contracts When Entered Into During Period" represents the fair value of
long- term contracts entered into with customers during 2002. The fair value is
calculated as of the execution of the contract. Most of the fair value comes
from longer term fixed price contracts with customers that seek to limit their
risk against fluctuating energy prices. The contract prices are valued against
market curves representative of the delivery location.
(c) Net Option Premiums Paid/(Received)" reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option contracts
that were entered into in 2002. (d) The Company changed the discount rate
applied to its trading portfolio from BBB+ Utility to LIBOR in the second
quarter which increased fair value by $10 million. In addition, the Company
changed its methodology in valuing a spread option model so as to more
accurately reflect the exercising of power transactions at optimal prices which
reduced fair value by $9 million.
(e)"Change in Market Value of Energy Trading Contracts Allocated to Regulated
Jurisdictions" relates to the net gains of those contracts that are not
reflected in the Consolidated Statements of Operations. These net gains are
recorded as regulatory liabilities for those subsidiaries that operate in
regulated jurisdictions.
(f)"Changes in Market Value of Contracts" represents the fair value change in
the trading portfolio due to market fluctuations during the current period.
Market fluctuations are attributable to various factors such as supply/demand,
weather, storage, etc.
(g)"Net Fair Value of Energy Trading Contracts" does not reflect the changes in
fair value associated with derivative contracts designated as hedges and
therefore will not agree to the net fair value of the Energy Trading and
Derivative Contracts line items on the individual registrants' balance sheets.
Mark-to-Market Energy Trading and Derivative Contract Maturities - AEP
Fair Value of Contracts at December 31, 2002
--------------------------------------------
Maturities
(in millions)
AEP Consolidated Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
- -------------------- ------ --------- --------- ---------- -----
Prices Actively Quoted (a) $(32) $ 69 $ - $ - $ 37
Prices Provided by Other External
Sources (b) 24 189 11 - 224
Prices Based on Models and Other
Valuation Methods (c) (84) 13 36 24 (11)
---- ---- --- --- ----
Total $(92) $271 $47 $24 $250
==== ==== === === ====
Mark-to-Market Energy Trading and Derivative Contract Maturities- Registrant Subsidiaries
Fair Value of Contracts at December 31, 2002
--------------------------------------------
Maturities
(in thousands)
Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
- -------------------- ------ --------- --------- ---------- -----
APCo
Prices Provided by Other
External Sources (b) $14,352 $43,307 $ 3,018 $ - $ 60,677
Prices Based on Models and Other
Valuation Methods (c) 11,492 9,475 8,183 7,025 36,175
------- ------- ------- ------ --------
Total $25,844 $52,782 $11,201 $7,025 $ 96,852
======= ======= ======= ====== ========
CSPCo
Prices Provided by Other
External Sources (b) $ 9,657 $29,113 $ 2,028 $ - $ 40,798
Prices Based on Models and Other
Valuation Methods (c) 7,726 6,370 5,501 4,722 24,319
------- ------- ------- ------ --------
Total $17,383 $35,483 $ 7,529 $4,722 $ 65,117
======= ======= ======= ====== ========
KPCo
Prices Provided by Other
External Sources (b) $ 3,707 $11,176 $ 779 $ - $ 15,662
Prices Based On Models and Other
Valuation Methods (c) 2,966 2,442 2,114 1,814 9,336
------- ------- ------- ------ --------
Total $ 6,673 $13,618 $ 2,893 $1,814 $ 24,998
======= ======= ======= ====== ========
I&M
Prices Provided by Other
External Sources (b) $12,105 $30,961 $ 2,171 $ - $ 45,237
Prices Based on Models and Other
Valuation Methods (c) 7,913 6,772 5,886 5,053 25,624
------- ------- ------- ------ --------
Total $20,018 $37,733 $ 8,057 $5,053 $ 70,861
======= ======= ======= ====== ========
OPCo
Prices Provided by Other
External Sources (b) $20,775 $38,622 $ 2,691 $ - $ 62,088
Prices Based on Models and Other
Valuation Methods (c) 10,003 8,453 7,298 6,264 32,018
------- ------- ------- ------ --------
Total $30,778 $47,075 $ 9,989 $6,264 $ 94,106
======= ======= ======= ====== ========
PSO
Prices Provided by Other
External Sources (b) $ 373 $1,736 $ 125 $ - $ 2,234
Prices Based on Models and Other
Valuation Methods (c) 296 390 336 289 1,311
------- ------ ------- ------- --------
Total $ 669 $2,126 $ 461 $ 289 $ 3,545
======= ====== ======= ======= ========
SWEPCo
Prices Provided by Other
External Sources (b) $ 427 $1,983 $ 141 $ - $ 2,551
Prices Based on Models and Other
Valuation Methods (c) 338 446 385 330 1,499
------- ------ ------- ------- --------
Total $ 765 $2,429 $ 526 $ 330 $ 4,050
======= ====== ======= ======= ========
TCC
Prices Provided by Other
External Sources (b) $ 1,536 $ 1,605 $ 115 $ - $ 3,256
Prices Based on Models and Other
Valuation Methods (c) 1,219 361 311 267 2,158
------- ------- -------- ------- --------
Total $ 2,755 $ 1,966 $ 426 $ 267 $ 5,414
======= ======= ======== ======= ========
TNC
Prices Provided by Other
External Sources (b) $ 201 $1,016 $ 73 $ - $ 1,290
Prices Based on Models and Other
Valuation Methods (c) 159 229 197 168 753
------- ------ -------- ------ --------
Total $ 360 $1,245 $ 270 $ 168 $ 2,043
======= ====== ======== ====== ========
(a)"Prices Actively Quoted" represents the Company's exchange traded futures
positions.
(b)"Prices Provided by Other External Sources" represents the
Company's positions in
natural gas, power, and coal at points where over-the-counter broker quotes
are available. Some prices from external sources are quoted as strips (one
bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been
included in this category.
(c)"Prices Based on Models and Other Valuation Methods" contain the following:
the value of the Company's adjustments for liquidity and counterparty credit
exposure, the value of contracts not quoted by an exchange or an
over-the-counter broker, the value of transactions
for which an internally developed price curve was developed as a result of
the long dated nature of certain transactions, and the value of certain
structured transactions.
We have investments in debt and equity securities which are held in nuclear
trust funds. The trust investments and their fair value are discussed in Note
17, "Risk Management, Financial Instruments and Derivatives." Financial
instruments in these trust funds have not been included in the market risk
calculation for interest rates as these instruments are marked-to-market and
changes in market value of these instruments are reflected in a corresponding
decommissioning liability. Any differences between the trust fund assets and the
ultimate liability are expected to be recovered through regulated rates from our
regulated customers.
Inflation affects our cost of replacing operating and maintaining utility plant
assets. The rate-making process limits recovery to the historical cost of
assets, resulting in economic losses when the effects of inflation are not
recovered from customers on a timely basis. However, economic gains that result
from the repayment of long-term debt with inflated dollars partly offset such
losses.
Industry Restructuring
Four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which AEP's domestic electric utility companies operate have
implemented retail restructuring legislation. Three other states (Arkansas,
Oklahoma and West Virginia) initially adopted retail restructuring legislation,
but have since delayed the implementation of that legislation or repealed the
legislation (Arkansas). In general, retail restructuring legislation provides
for a transition from cost-based rate regulation of bundled electric service to
customer choice and market pricing for the supply of electricity. As legislative
and regulatory proceedings evolved, six AEP electric operating companies (APCo,
CSPCo, OPCo, SWEPCo, TCC and TNC) have discontinued the application of SFAS 71
regulatory accounting for the generation business. AEP has not discontinued its
regulatory accounting for its subsidiaries doing business in Michigan (I&M) and
Oklahoma (PSO). Restructuring legislation, the status of the transition plans
and the status of the electric utility companies' accounting to comply with the
changes in each of our state regulatory jurisdictions affected by restructuring
legislation is presented in Note 8 of the Notes to Financial Statements.
Corporate Separation
AEP and its subsidiaries have filed with the FERC and SEC seeking approval to
separate their regulated and unregulated operations. The plan for corporate
separation allows AEP and its subsidiaries to meet the requirements of Texas and
Ohio restructuring legislation. In Texas, TCC and TNC intended to transfer the
generation assets from the integrated electric operating companies (CPL and WTU)
which operated in ERCOT prior to the effective date of the Texas Restructuring
Legislation to unregulated generation companies. In Ohio, CSPCo and OPCo
intended to transfer transmission and distribution assets from the integrated
companies to two new wires companies leaving CSPCo and OPCo as generating
companies. AEP and its subsidiaries proposed amendments to the power pooling
agreements to remove the four Ohio and Texas generating companies. Only those
operating companies that continue to exist as integrated utilities would have
been included in the amended power pooling agreements, which would govern energy
exchanges among members and the allocation of their off-system purchases and
sales. In connection with corporate seperation, certain new interim power supply
agreements have been proposed to provide power to distribution companies who
will no longer own generation assets. Several state commissions, wholesale
customer groups and other interested parties intervened in the FERC proceeding.
Negotiated settlement agreements with the state regulatory commissions and other
major intervenors were filed with the FERC in December 2001. In September 2002,
the FERC conditionally approved our corporate separation plan as modified by the
settlement agreements. Terms in the settlement agreements would be effective
upon implementation of corporation separation. In addition, SEC approval of
AEP's corporate separation plan is required for its implementation. The Arkansas
Commission intervened with the SEC, which has extended the length of time needed
for the SEC's review. In order to execute this separation, AEP and its
subsidiaries may be required to retire various debt securities and transfer
assets between legal entities.
With the changes in AEP's business strategy in response to current energy
market/business conditions, management is evaluating changes to the corporate
separation plans, including determining whether legal corporate separation is
appropriate.
RTO Formation
FERC Order No. 2000 and many of the settlement agreements with the FERC and
state regulatory commissions to approve the AEP-CSW merger required the transfer
of functional control of the subsidiaries' transmission systems to RTOs.
AEP East companies initially participated in the formation of the Alliance RTO.
In December 2001, the FERC reversed prior approvals and rejected the Alliance
RTO's filing. Subsequently, in May 2002, AEP announced an agreement with the PJM
Interconnection to pursue terms for AEP East companies to participate in PJM
with final agreements to be negotiated. In July 2002, the FERC conditionally
approved AEP's decision for AEP East companies to join PJM subject to certain
conditions being met. The performance of these conditions are only partially
under AEP's control. In December 2002, AEP East companies in Indiana, Kentucky,
Ohio and Virginia filed for state regulatory commission approval of their plans
to transfer functional control of their transmission assets to PJM based on
statutory or regulatory requirements in those states. Those proceedings are
currently pending. In February 2003, the Virginia Legislature enacted
legislation that would prohibit the transfer to an RTO, until at least July
2004, which is currently awaiting signature by the Governor of Virginia.
AEP West companies are members of ERCOT or the SPP. In May 2002, FERC accepted,
conditionally, filings related to a proposed consolidation of the MISO and the
SPP. In that order the FERC required the AEP West companies in SPP to file
reasons why they should not be required to join MISO. In August 2002, AEP,
SWEPCo and TNC notified the FERC of their intent that the transmission assets in
SPP would participate in MISO. AEP's SPP companies are also regulated by state
public utility commissions, and the Louisiana and Arkansas commissions also
filed responses to the FERC's RTO order indicating that additional analysis was
required. Regulatory activities concerning various RTO issues are ongoing in
Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory
actions and proceedings or their impact on the timing and operation of RTOs, AEP
and its subsidiaries' transmission operations or future results of operations
and cash flows.
FERC Proposed Standard Market Design and Security Standards
In 2002, the FERC issued its Standard Market Design (SMD) notice of proposed
rulemaking seeking to standardize the structure and operation of wholesale
electricity markets across the country. The FERC published for comment its
proposed security standards as part of the SMD. These standards are intended to
ensure all market participants have a basic security program that effectively
protects the electric grid and related market activities. Because the rule is
not yet finalized, management cannot predict the effect of the final rule on AEP
or its subsidiaries' operations and financial results. See Note 9 for a complete
discussion of these proposals.
Litigation
AEP and its subsidiaries are involved in various litigation. The details of
significant litigation contingencies are disclosed in Note 9 and summarized
below.
Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corp. and its subsidiaries which are pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's bankruptcy,
AEP and its subsidiaries had open trading contracts and trading accounts
receivables and payables with Enron and various HPL related contingencies and
indemnities including issues related to the underground Bammel gas storage
facility and the cushion gas (or pad gas) required for its normal operation.
In 2001, AEP expensed $47 million ($31 million net of tax) for our estimated
loss from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million
for a cumulative loss of $53 million ($34 million net of tax). The amounts for
certain subsidiary registrants were:
Amounts
Amounts Net of
Registrant Expensed Tax
-------- -----
(in millions)
APCo $5.3 $3.4
CSPCo 2.7 1.8
I&M 2.8 1.8
KPCo 1.1 0.7
OPCo 3.6 2.3
The additional 2002 expense did not materially change the cumulative expense per
registrant subsidiary. The amounts expensed were based on an analysis of
contracts where AEP entities and Enron are counterparties.
Management believes that we have the right to utilize offsetting receivables and
payables and related collateral across various Enron entities by offsetting
approximately $110 million of trading payables owed to various Enron entities
against trading receivables due to us. Management believes we have legal
defenses to any challenge that may be made to the utilization of such offsets.
At this time management is unable to predict the ultimate resolution of these
issues or their impact on results of operations and cash flows. See Note 9 for
further discussion.
COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
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.
The earnings reductions for affected registrant subsidiaries were as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
AEP has appealed the Court's decision. See Note 18 for further discussion.
Shareholders' Litigation - Affecting AEP
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against AEP, certain
AEP executives, members of the AEP Board of Directors and certain investment
banking firms. These cases are in the initial pleading stage. AEP intends to
vigorously defend against these actions. See Note 9 for further discussion.
California Lawsuit - Affecting AEP
In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP intends to
vigorously defend against this action. See Note 9 for further discussion.
FERC Wholesale Fuel Complaints - Affecting AEP and TNC
In May 2000 and November 2001, certain TNC wholesale customers filed a
complaints with FERC alleging that TNC had overcharged them through the fuel
adjustment clause for certain purchased power costs. The final resolution of
this matter could have a negative impact on futute results of operations, cash
flow and financial condition. See Note 6 for further discussion.
Merger Litigation - Affecting AEP and all Subsidiary Registrants
In January 2002, a federal court ruled that the SEC did not properly find that
the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and
sent the case back to the SEC for further review. Management believes that the
merger meets the requirements of the PUHCA and expects the matter to be resolved
favorably. See Note 9 for further discussion.
Arbitration of Williams Claim - Affecting AEP
In 2002, AEP filed its demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
Although management is unable to predict the outcome of this matter, it is not
expected to have a material impact on results of operations, cash flows or
financial condition. See Note 9 for further discussion.
Energy Market Investigations - Affecting AEP
During 2002, the FERC, the California attorney general, the PUCT, the SEC, the
Department of Justice and the U.S. Commodity Futures Trading Commission (CFTC)
initiated investigations into whether any entity, including Enron, manipulated
short-term prices in electric energy or natural gas markets, exercised undue
influence over wholesale prices or participated in fraudulent trading practices.
AEP and its subsidiaries have and will continue to provide information to the
FERC, the SEC, state officials and the CFTC as required. See Note 9 for further
discussion.
FERC Market Power Mitigation - Affecting the AEP System
A FERC order on our triennial market based wholesale power rate authorization
update required certain mitigation actions that AEP and its subsidiaries would
need to take for sales/purchases within their control area and required the
posting of information on our website regarding the status of AEP's power
system. As a result of a request for rehearing filed by AEP and other market
participants, FERC issued an order delaying the effective date of the mitigation
plan until after a planned technical conference on market power determination.
No such conference has been held and management is unable to predict the timing
of any further action by the FERC or its affect on future results of operations
and cash flows.
Other Litigation - Affecting AEP and all Subsidiary Registrants
AEP and its subsidiaries are involved in a number of other legal proceedings and
claims. While management is unable to predict the outcome of such litigation, it
is not expected that the ultimate resolution of these matters will have a
material adverse effect on results of operations, cash flows or financial
condition.
Environmental Concerns and Issues
AEP and its subsidiaries will confront several new environmental requirements
over the next decade with the potential for substantial control costs and
premature retirement of some generating plants. These policies include:
stringent controls on sulfur dioxide (S02), nitrogen oxide (NOx) and mercury
(Hg) emissions from future regulations or laws, or an adverse decision in the
New Source Review litigation; a new Clean Water Act rule to reduce fish killed
at once-through cooled power plants; and a possible future requirement to reduce
carbon dioxide (CO2) emissions as the world endeavors to stabilize atmospheric
concentrations of greenhouse gas emissions and avert global climatic changes.
AEP and its subsidiaries' environmental policy require full compliance with all
applicable legal requirements. In support of this policy, AEP and its
subsidiaries invest in research through groups like the Electric Power Research
Institute and directly through demonstration projects for new emission control
technologies. AEP and its subsidiaries intend to continue in a leadership role
to protect and preserve the environment while providing vital energy commodities
and services to customers at fair prices. AEP and its subsidiaries have a proven
record of efficiently producing and delivering electricity and gas while
minimizing the impact on the environment. AEP and its subsidiaries have spent
billions of dollars to equip many of their facilities with pollution control
technologies.
Multi-pollutant control legislation has been introduced in Congress and is
supported by the Bush Administration. The legislation would regulate NOx, SO2,
Hg and possibly CO2 emissions from electric generating plants. AEP and its
subsidiaries are advocates of comprehensive, multi-pollutant legislation so that
compliance planning can be coordinated and collateral emission reductions
maximized. Optimally, such legislation would establish reasonable emission
reduction targets and compliance timetables based on sound science, utilize
nationwide cap-and-trade programs for achieving compliance as cost-effectively
as possible, protect fuel diversity and preserve the reliability of the nation's
electric supply. Management is unable to predict the timing or magnitude of
additional pollution control laws or regulations. If additional control
technology is required on AEP System facilities and their costs are not
recoverable from customers through regulated rates or market prices, those costs
could adversely affect future results of operations and cash flows. The
following discussions explain existing control efforts, litigation and other
pending matters related to environmental issues for AEP companies.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M
and OPCo
Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. Federal EPA, a
number of states and special interest groups alleged that AEP System companies
modified certain units at coal fired generating plants in violation of the Clean
Air Act over a 20 year period.
Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense.
Management is unable to estimate the loss or range of loss related to the
contingent liability under the Clear Air Act proceedings and unable to predict
the timing of resolution of these matters due to the number of alleged
violations and the significant number of issues yet to be determined by the
Court. If the AEP System companies do not prevail, any capital and operating
costs of additional pollution control equipment or any penalties imposed would
adversely affect future results of operations, cash flows and possibly financial
condition unless such costs can be recovered. See Note 9 for further discussion.
NOx Reductions - Affecting AEP, APCo, I&M, OPCo, SWEPCo and TCC
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
requiring substantial reductions in NOx emissions in a number of eastern states,
including certain states in which the AEP System's generating plants are
located. The compliance date for these rules is May 31, 2004.
In 2000, the Texas Commission on Environmental Quality (formerly the Texas
Natural Resource Conservation Commission) adopted rules requiring significant
reductions in NOx emissions from utility sources, including TCC and SWEPCo. The
compliance date is May 2003 for TCC and May 2005 for SWEPCo.
AEP and its subsidiaries are installing a variety of emission control
technologies to reduce NOx emissions to comply with the applicable state and
Federal NOx requirements including selective catalytic reduction (SCR) and
non-SCR technologies. The AEP System NOx compliance plan is a dynamic plan that
is continually reviewed and revised. Current estimates indicate that compliance
with the NOx Rule, the Texas Commission on Environmental Quality rule and the
Section 126 Rule could result in required capital expenditures in the range of
$1.3 billion to $2 billion of which $843 million has been spent through December
31, 2002 for the AEP System.
The following table shows the estimated compliance cost ranges and amounts spent
by certain of AEP's registrant subsidiaries through December 31, 2002.
Estimated Amounts
Compliance Costs Spent
---------------- -------
(in millions)
Company
APCo $445 $234
I&M 42-210 5
OPCo 535-864 387
SWEPCo 40 24
TCC 5 5
Unless any capital and operating costs of additional pollution control equipment
are recovered from customers, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition. See Note 9 for
further discussion.
Superfund and State Remediation - Affecting AEP, APCo, CSPCo, I&M, OPCo, SWEPCo
and TCC
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. AEP and its subsidiaries are currently incurring costs to safely
dispose of these substances. Additional costs could be incurred to comply with
new laws and regulations if enacted.
Superfund addresses clean-up of hazardous substances at disposal sites and
authorized Federal EPA to administer the clean-up programs. As of year-end 2002
subsidiaries of AEP are named by the Federal EPA as a PRP for five sites. APCo,
CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are six
additional sites for which APCo, CSPCo, I&M, KPCo, OPCo and SWEPCo have received
information requests which could lead to PRP designation. HPL, OPCo, SWEPCo and
TCC 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 AEP or its subsidiaries have
been named a PRP or defendant, their disposal or recycling activities were in
accordance with the then-applicable laws and regulations. Unfortunately,
Superfund does not recognize compliance as a defense, but imposes strict
liability on parties who fall within its broad statutory categories.
While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding AEP subsidiaries'
potential future liability. Disposal of materials at a particular site is often
unsubstantiated and the quantity of materials deposited at a site was small and
often nonhazardous. Although 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 AEP subsidiaries have been declared PRPs. If significant cleanup
costs are attributed to AEP or its subsidiaries in the future under Superfund,
results of operations, cash flows and possibly financial condition would be
adversely affected unless the costs can be recovered from customers.
Global Climate Change - Affecting AEP and all Registrant Subsidiaries
At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997, more than
160 countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly CO2, which many scientists
believe are contributing to global climate change. Although the U.S. signed the
Kyoto Protocol on November 12, 1998, the treaty was not submitted to the Senate
for its advice and consent by President Clinton. In March 2001, President Bush
announced his opposition to the treaty and its U.S. ratification. At the Seventh
Conference of the Parties in November 2001, the parties finalized the rules,
procedures and guidelines required to facilitate ratification of the protocol.
The protocol is expected to become effective in 2003. AEP does not support the
Kyoto Protocol but intends to work with the Bush Administration and U.S.
Congress to develop responsible public policy on this issue. Management expects
that due to President Bush's opposition to legislation mandating greenhouse gas
emissions controls, any policies developed and implemented in the near future
are likely to encourage voluntary measures to reduce, avoid or sequester such
emissions. AEP has for many years been a leader in pursuing voluntary actions to
control greenhouse gas emissions. AEP recently expanded its commitment in this
area by
joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction
and trading program, under which AEP and its subsidiaries are obligated to
reduce or offset 18 million tons of CO2 emissions during 2003-2006.
The acquisition of 4,000 MW of coal-fired generation in the United Kingdom in
December 2001 exposes these assets to potential CO2 emission control obligations
since the U.K has become a party to the Kyoto Protocol.
Control of Mercury Emissions
In December 2000, Federal EPA issued a regulatory determination listing the
electric generating sector as a source category under the Clean Air Act for
development of maximum achievable control technology standards to control
emissions of hazardous air pollutants, including Hg. Federal EPA is expected to
issue proposed regulations in 2003 and develop a final rule in 2004. Management
cannot predict the outcome of these regulatory proceedings, or the costs to
comply with any new standards adopted by Federal EPA. The costs associated with
compliance could be material. However, unless any capital and operating costs of
additional pollution control equipment are recovered from customers, they will
have an adverse effect on future results of operations, cash flows and possibly
financial condition.
Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, I&M and TCC
I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a
significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law I&M and TCC participate in the DOE's
SNF disposal program which is described in Note 9 of the Notes to Financial
Statements. Since 1983 I&M has collected $303 million from customers for the
disposal of nuclear fuel consumed at the Cook Plant. $117 million of these funds
have been deposited in external trust funds to provide for the future disposal
of SNF and $186 million has been remitted to the DOE. TCC has collected and
remitted to the DOE, $53 million for the future disposal of SNF since STP began
operation in the late 1980s. Under the provisions of the Nuclear Waste Policy
Act, collections from customers are to provide the DOE with money to build a
permanent repository for spent fuel. However, in 1996, the DOE notified the
companies that it would be unable to begin accepting SNF by the January 1998
deadline required by law. To date DOE has failed to comply with the requirements
of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and
STPNOC on behalf of TCC and the other STP owners, along with a number of
unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. On January 17,
2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of
liability. The case continues on the issue of damages owed to I&M by the DOE. As
long as the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and permanent storage
of SNF and the cost of decommissioning will continue to increase.
In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined a
lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related
to DOE's nuclear waste fund cost recovery settlement with PECO Energy
Corporation (now Exelon Generation Company, LLC). The settlement adjusted the
fees Exelon was required to pay to DOE for disposal of SNF. The fee adjustment
allowed Exelon to skip payments to the DOE to make up for Exelon's damages from
DOE's breach of its contract obligation to dispose of SNF from commercial
nuclear power plants. The companies believe the settlement was unlawful as it
would force other utilities (rather than DOE) to compensate Exelon for the
damages it had incurred from DOE's breach of contract. In September 2002, the
U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly
by adopting the fee adjustment provision of this settlement, that the fee
adjustment provisions of the settlement harmed other utilities who pay into the
fund and violated the federal nuclear waste management laws and that the fee
adjustment provisions of the settlement were null and void.
The cost to decommission nuclear plants is affected by both NRC regulations and
the delayed SNF disposal program. Studies completed in 2000 estimate the cost to
decommission the Cook Plant ranges from $783 million to $1,481 million in 2000
non-discounted dollars. External trust funds have been established with amounts
collected from customers to decommission the plant. At December 31, 2002, the
total decom-missioning trust fund balance for Cook Plant was $618 million which
includes earnings on the trust investments. Studies completed in 1999 for STP
estimate TCC's share of decommissioning cost to be $289 million in 1999
non-discounted dollars. Amounts collected from customers to decommission STP
have been placed in an external trust. At December 31, 2002, the total
decommission-ing trust fund for TCC's share of STP was $98 million which
includes earnings on the trust investments. Estimates from the decommissioning
studies could continue to escalate due to the uncertainty in the SNF disposal
program and the length of time that SNF may need to be stored at the plant site.
I&M and TCC will work with regulators and customers to recover the remaining
estimated costs of decommissioning Cook Plant and STP. However, AEP's, I&M's and
TCC's future results of operations, cash flows and possibly their financial
conditions would be adversely affected if the cost of SNF disposal and
decommissioning continues to increase and cannot be recovered.
Other Environmental Concerns - Affecting AEP and all Subsidiaries
AEP and its subsidiaries are exposed to other environmental concerns which are
not considered to be material or potentially material at this time. Should they
become significant or should any new concerns be uncovered that are material,
they could have a material adverse effect on results of operations and possibly
financial condition. AEP performs environmental reviews and audits on a regular
basis for the purpose of identifying, evaluating and addressing environmental
concerns and issues.
Other Matters
Seasonality
Sale of electric power is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change depending on the nature and location
of facilities AEP and its subsidiaries acquire and the terms of power sale
contracts they enter. In addition, AEP and its subsidiaries have historically
sold less power, and consequently earned less income, when weather conditions
are milder. AEP and its subsidiaries expect that unusually mild weather in the
future could diminish their results of operations and may impact their financial
condition.
Sustained Earnings Improvement Initiative
In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth. Termination benefits expense relating to 1,120 terminated
employees totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. We determined that the termination of the employees under our SEI
initiative did not constitute a curtailment under the provisions of SFAS No. 88
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits". In addition, certain buildings and
corporate aircraft are being sold in an effort to reduce ongoing operating
expenses. See Note 11 for additional information.
Non-Core Wholesale Investments
Additional market deterioration associated with AEP's non-core wholesale
investments, including AEP's U.K. operations, could have an adverse impact on
AEP's future results of operations and cash flows. Significant long-term changes
in external market conditions could lead to additional write-offs and potential
divestitures of AEP's wholesale investments, including, but not limited to,
AEP's U.K. operations.
Elk City Referendum - Affecting AEP and PSO
In October 2002, the City Commission of Elk City, Oklahoma voted to hold a
referendum seeking voter approval of a $20.4 million acquisition of PSO's
distribution assets within the city limits. The vote occurred in December 2002
with the referendum being defeated.
Snohomish Settlement - Affecting AEP
In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract.
Investments Limitations - Affecting AEP
Our investment, including guarantees of debt, in certain types of activities is
limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling
securities in an amount up to 100% of our average quarterly consolidated
retained earnings balance for investment in EWGs and FUCOs. At December 31,
2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including guarantees
of debt, compared to AEP's limit of $2.8 billion.
SEC rules under PUHCA permit AEP to invest up to 15% of consolidated
capitalization (such amount was $3.2 billion at December 31, 2002) in
energy-related companies, including marketing and/or trading of electricity, gas
and other energy commodities.
INVESTOR INQUIRIES
Investors should direct inquiries to Investor Relations using the toll free
number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of
Investor Relations American Electric Power Service Corporation 28th Floor 1
Riverside Plaza Columbus, OH 43215-2373
FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities and Exchange Commission will
be available in April 2003 at no cost to shareholders.
Please address requests for copies to:
R. Todd Rimmer
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH 43215-2373
TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK
Equiserve Trust Company, N.A.
P.O. Box 43069
Providence, RI 02940-3069
Phone Number: 1-800-328-6955
Hearing Impaired Number: TDD: 1-800-952-9245
Website: http://www.equiserve.com