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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended JUNE 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
------ ------
Commission Registrant, State of Incorporation I.R.S. Employer
File Number Address, and Telephone Number Identification No.
- ----------- ----------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600
0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
All Registrants 1 Riverside Plaza, Columbus, Ohio 43215-2373
Telephone (614) 716-1000
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark whether American Electric Power Company, Inc. is an
accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes X No
----- -----
Indicate by check mark whether 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 and Southwestern Electric
Power Company, are accelerated filers (as defined in Rule 12b-2 of the Exchange
Act).
Yes No X
----- -----
AEP Generating Company, AEP Texas North Company, Columbus Southern Power
Company, Kentucky Power Company and Public Service Company of Oklahoma meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at July 31, 2003 was 395,001,853.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2003
Page
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Glossary of Terms i - iii
Forward-Looking Information iv
Part I. FINANCIAL INFORMATION
Items 1 and 2 Financial Statements and Management's Financial Discussion and Analysis:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Financial Discussion and Analysis A-1 - A-16
Consolidated Financial Statements A-17 - A-21
Notes to Consolidated Financial Statements A-22 - A-50
AEP Generating Company:
Management's Narrative Financial Discussion and Analysis B-1
Financial Statements B-2 - B-5
AEP Texas Central Company and Subsidiaries:
Management's Financial Discussion and Analysis C-1 - C-6
Consolidated Financial Statements C-7 - C-11
AEP Texas North Company:
Management's Narrative Financial Discussion and Analysis D-1 - D-5
Financial Statements D-6 - D-10
Appalachian Power Company and Subsidiaries:
Management's Financial Discussion and Analysis E-1 - E-6
Consolidated Financial Statements E-7 - E-11
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Financial Discussion and Analysis F-1 - F-6
Consolidated Financial Statements F-7 - F-11
Indiana Michigan Power Company and Subsidiaries:
Management's Financial Discussion and Analysis G-1 - G-7
Consolidated Financial Statements G-8 - G-12
Kentucky Power Company:
Management's Narrative Financial Discussion and Analysis H-1 - H-5
Financial Statements H-6 - H-10
Ohio Power Company:
Management's Financial Discussion and Analysis I-1 - I-6
Financial Statements I-7 - I-11
Public Service Company of Oklahoma and Subsidiary:
Management's Narrative Financial Discussion and Analysis J-1 - J-4
Consolidated Financial Statements J-5 - J-9
Southwestern Electric Power Company and Subsidiaries:
Management's Financial Discussion and Analysis K-1 - K-5
Consolidated Financial Statements K-6 - K-10
Notes to Respective Financial Statements L-1 - L-20
Item 4. Controls and Procedures M-1
Part II. OTHER INFORMATION
Item 1. Legal Proceedings N-1
Item 4. Submission of Matters to a Vote of Security Holders N-2
Item 5. Other Information N-4
Item 6. Exhibits and Reports on Form 8-K N-4
(a) Exhibits:
Exhibit 12
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
(b) Reports on Form 8-K
SIGNATURES O-1
This combined Form 10-Q is separately filed by 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 and Southwestern Electric Power Company.
Information contained herein relating to any individual registrant is filed
by such registrant on its own behalf. Each registrant makes no representation
as to information relating to the other registrants.
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 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.
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.
COLI Corporate owned life insurance program.
Cook Plant The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
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. DOE United States Department of Energy.
ECOM Excess Cost Over Market.
EITF The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3 Emerging Issues Task Force Issue No. 02-3: Issues Involved in Accounting for Derivative
Contracts Held For Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities.
ERCOT The Electric Reliability Council of Texas.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FIN 45 FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
FIN 46 FASB Interpretation No. 46" Consolidation of Variable Interest Entities"
GAAP Generally Accepted Accounting Principles.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR Interchange Cost Reconstruction.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
ISO Independent System Operator.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
KWH Kilowatthour.
LIG Louisiana Intrastate Gas.
LPSC Louisiana Public Service Commission
Michigan Legislation The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool AEP System's Money Pool.
MPSC Michigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx Nitrogen oxide.
NOx Rule A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including
seven of the states in which AEP companies operate.
NRC Nuclear Regulatory Commission.
OCC The Corporation Commission of the State of Oklahoma.
Ohio Act The Ohio Electric Restructuring Act of 1999.
Ohio EPA Ohio Environmental Protection Agency.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
PJM Pennsylvania - New Jersey - Maryland regional transmission organization.
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.
------------------------------------------------------------
SFAS 143 Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Operations.
------------------------------------------
SFAS 149 Statement of Financial Accounting Standards No. 149,
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
---------------------------------------------------------------------------
SFAS 150 Statement of Financial Accounting Standards No. 150,
Accounting for Certain Financial Instruments with Characteristics of both Liabilities
-------------------------------------------------------------------------------------
and Equity.
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SNF Spent Nuclear Fuel.
SPP Southwest Power Pool.
STP South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
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)].
Tenor Maturity of a contract.
Texas Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
Utilities Company (WTU)].
TVA Tennessee Valley Authority.
U.K. The United Kingdom.
VaR Value at Risk, a method to quantify risk exposure.
Virginia SCC Virginia State Corporation Commission.
WVPSC Public Service Commission of West Virginia.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
Zimmer Plant William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
FORWARD-LOOKING INFORMATION
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
deregulation.
o New legislation and government regulation.
o Oversight and/or investigation of the energy sector or its
participants.
o Our ability to successfully control 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 foreign
investments including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in our service territory and changes
in market demand and demographic patterns.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates.
o Liquidity in the banking, capital and wholesale power markets.
o Actions of rating agencies.
o Changes in technology, including the increased use of distributed
generation within our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
- ---------------------
American Electric Power Company's consolidated Net Income (Loss) by operating
segment for the quarter and year-to-date periods ended June 30, 2003 and 2002
were as follows:
Three Months Ended Six Months Ended
2003 2002 2003 2002
---- ---- ---- ----
(in millions)
Utility Operations $222 $228 $750 $ 441
Investments - Gas Operations (24) (32) (61) (80)
Investments - UK Operations 3 (12) (59) 11
Investments - Other (26) (122) (15) (479)
---- ---- ---- -----
Total $175 $ 62 $615 $(107)
==== ==== ==== =====
Our Net Income is discussed below according to the operating segments listed
above. Income Before Discontinued Operations and Cumulative Effect
for the quarter and year-to-date were affected by the weather, weak economy and
the availability of electric generation. Year-to-date Net Income of $615
million or $1.64 per share includes $242 million (net of tax) of Income from
Cumulative Effect of Accounting Changes in the first quarter resulting from
the implementation of SFAS 143 (see Note 4) partially offset by $49 million
(net of tax) of Loss from Cumulative Effect of Accounting Changes in the first
quarter resulting from the implementation of EITF 02-3 (see Note 4) and
discontinued operations of $16 million loss (net of tax) (see Note 11). The
loss of $107 million year-to-date 2002 includes discontinued operations of $74
million loss (net of tax) (see Note 11) and a $350 million (net of tax) charge
discussed below in the Investments - Other segment for the implementation of
SFAS 142 (see Note 4).
Utility Operations
Net Income for Utility Operations, our core business, decreased in the quarter
$6 million and increased year-to-date $309 million due to the fluctuations in
operating income along with the year-to-date adjustment for the cumulative
effect of accounting changes. Year-to-date Net Income of $750 million included
$249 million (net of tax) of Income from Cumulative Effect of Accounting Changes
in the first quarter resulting from the implementation of SFAS 143 (see Note 4)
partially offset by $11 million (net of tax) Loss from Cumulative Effect of
Accounting Changes in the first quarter resulting from the implementation of
EITF 02-3 (see Note 4). Operating income decreased in the second quarter and
increased on a year-to-date basis primarily due to:
o Pre-tax earnings increased $59 million in the quarter and $116 million
year-to-date resulting primarily from the non-cash earnings associated
with the stranded cost recovery in Texas which recognizes the
difference between the actual price received from the state-mandated
auction of 15% of generation capacity and the earlier estimate of
market price derived by the PUCT model. This regulatory asset is
expected to be recovered through the 2004 true-up proceeding
established by deregulation laws in Texas.
o Pre-tax earnings for systems sales, transmission revenue and other
wholesale transactions decreased $7 million in the current quarter as a
result of our exit from trading markets where we do not own assets.
Year-to-date pre-tax earnings increased by $66 million due to favorable
power optimization and higher transmission volumes.
o Retail margins from the regulated integrated utilities reduced
pre-tax earnings by $64 million for the quarter and $61 million
year-to-date due to the combined impact of weather, continued weak
economy and costs associated with the Cook Plant outage.
o The reduced demand in the Ohio Companies attributable to the mild
weather in the quarter and the economic pressures on industrial
customers reduced pre-tax earnings by $15 million. Year-to-date pre-tax
earnings increased $5 million due to the average fuel costs being less
than the set recovery rate in revenues.
o The reduction in pre-tax earnings of $38 million for the quarter and
$83 million year-to-date of Texas supply is due to lower margins
attributable to an outage at the STP nuclear plant and a separate
provision for potential disallowance by the PUCT of certain historical
fuel expenses. The Texas supply represents the gross margin for output
of generating units in the ERCOT region and from "reliability must run"
(RMR) contracts with ERCOT.
o Federal Income Taxes decreased $21 million in the quarter and
increased $19 million year-to-date due to the fluctuation in
pre-tax income and the changes in the effective tax rate.
Investments - Gas Operations
Net Loss for the Gas Operations, which include Louisiana Intrastate Gas and
Houston Pipe Line operations, of $24 million in the quarter and $61 million
year-to-date is due to lower margins resulting from our reduced risk profile
and the year-to-date adjustment for the cumulative effect of accounting
changes. These decreases were partially offset by reduced operating and
interest expenses. Year-to-date Net Loss of $61 million included $23 million
(net of tax) of Loss from Cumulative Effect of Accounting Changes in
the first quarter resulting from the implementation of EITF 02-3 (see Note 4).
We have selected advisors to assist with developing a plan of divestiture of its
Louisiana Intrastate Gas holdings. See "Significant Factors - Possible
Divestitures" for additional information.
Investments- UK Operations
Net Loss for the UK Operations, which include Fiddler's Ferry and Ferrybridge
plants (FFF), decreased in the quarter $15 million and increased year-to-date
$70 million due to the fluctuations in operating income along with the
year-to-date adjustment for the cumulative effect of accounting changes.
Year-to-date Net Loss of $59 million included $15 million (net of tax) of Loss
from Cumulative Effect of Accounting Changes in the first quarter resulting from
the implementation of EITF 02-3 (see Note 4) and a $7 million (net of tax) Loss
from Cumulative Effect of Accounting Changes in the first quarter from the
implementation of SFAS 143 (see Note 4). During the second quarter, our U.K.
operations' improved performance was driven primarily by the results of our coal
and freight procurement group and reduced interest expense, as the debt
associated with the plants was retired in early April. Year-to-date our U.K.
operations posted a loss of $37 million driven by a $40 million loss in the
first quarter, due to the continued deterioration in power markets during that
period, and higher operations and maintenance costs which included severance and
redundancy closure costs of the Nordic trading office. Significant liquidity
issues in the U.K. market and the uncertain environmental regulations are still
concerns, so we expect this market to remain a difficult one for the foreseeable
future.
Investments - Other
Net Loss for Other investments, which consists of investments in independent
power plants, coal mines, river transportation, and communications as well as
the discontinued operations of SEEBOARD, CitiPower, Eastex and Pushan, of $26
million in the current quarter 2003 and $15 million year-to-date reflects
discontinued operations losses of $7 million in the quarter and $16 million
year-to-date. The Loss Before Discontinued Operations and Cumulative Effect of
Accounting Changes decreased $7 million in the quarter and $56 million
year-to-date due to lower international development costs, reduced interest
expense and lower costs to wind down operations. The 2002 Net Loss for Other
investments of $122 million in the quarter and $479 million year-to-date
includes discontinued operations losses of $96 million in the quarter and $74
million year-to-date as well as a $350 million (net of tax) first quarter
cumulative effect adjustment for the implementation of SFAS 142 (see Note 4) .
SFAS 142 required 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 after tax net transitional
loss in 2002 for the SEEBOARD and CitiPower operations.
We have selected advisors to assist with developing a plan of divestiture of
coal mines and certain independent power plants. See "Significant Factors -
Possible Divestitures" for additional information.
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have AEP and our rated subsidiaries on stable
outlook. Current ratings for AEP are as follows:
Moody's S&P Fitch
------- --- -----
AEP Short-Term Debt P-3 A-2 F-2
AEP Senior Unsecured Debt Baa3 BBB BBB
Senior Notes issued by AEP
Resources (with support
Agreement from AEP) Baa3 BBB BBB+
During the first quarter of 2003, Moody's Investors Service (Moody's), Standard
& Poors (S&P) and Fitch Rating Service completed their reviews of AEP and our
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.
Liquidity
At June 30, 2003, our liquidity sources totaled $3.9 billion and we had an
available liquidity position of $3.3 billion as illustrated in the table below:
Credit Facilities
(in millions) Maturity
--------
Commercial Paper Backup:
Lines of Credit $ 750 5/04
Lines of Credit 1,000 5/05
Lines of Credit 750 5/06
Euro Revolving Credit
Facilities 345 10/03
------
Total 2,845
Liquidity Reserves 300*
Other Temporary
Investments 722*
------
Total Liquidity Sources 3,867
Less: Commercial Paper
Outstanding 547
------
Total Available Liquidity $3,320
======
* These components comprise the Cash and Cash Equivalents balance on our
Consolidated Balance Sheet at June 30, 2003 less $154 million of operational
cash on hand. We maintain the $300 million cash liquidity reserve fund to
support our marketing operations in the U.S. and keep additional cash on hand as
market conditions change.
In April 2003, our Board of Directors declared a common stock dividend of $0.35
per share for the second quarter of 2003, which is a 42% decrease from the
previous quarter's dividend of $0.60 per share. This reduction will result in
annual cash savings of approximately $395 million.
Cash Flow
Six Months Ended June 30,
2003 2002
--------- ---------
(in millions)
Cash and cash equivalents at beginning of period $1,213 $ 224
------ -------
Net cash from (used for) continuing operations:
Operating activities 798 $ 97
Investing activities (596) (784)
Financing activities (239) 1,038
Effect of exchange rate changes on cash and
cash equivalents - (14)
------ -------
Net increase (decrease) in cash and cash equivalents (37) 337
------ -------
Cash and cash equivalents at end of period $1,176 $ 561
====== =======
Cash from operations and short-term borrowings provide working capital and meet
other short-term cash needs. We generally use short-term borrowings to fund
property acquisitions and construction until long-term funding mechanisms are
arranged. Sources of long-term funding include issuance of common stock,
preferred stock or long-term debt and sale-leaseback or leasing agreements. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored receivables purchase agreement and three revolving credit
agreements.
Operating Activities
Cash flows from operating activities during the first half of 2003 were $798
million. Beginning with Income Before Discontinued Operations and Cumulative
Effect of Accounting Changes of $438 million, we add depreciation and deferred
taxes of $702 million and deduct $108 million of non-cash ECOM, $48 million in
mark-to-market changes and $190 million for working capital changes. The
negative working capital changes includes $90 million paid to Williams companies
in settlement for power and gas transactions, and $46 million in increased fuel
inventories.
Investing Activities
Cash flows used for investing activities during the first half of 2003 were $596
million compared to $784 million during the first half of 2002. The major reason
for the year-over-year variance was a construction expenditures reduction of
$135 million and proceeds of $41 million from the sale of assets in 2003 (see
Note 11).
Total consolidated plant and property additions for the first half 2003 were
$649 million, including continued construction expenditures for emission control
technology at several coal-fired generating plants (see Note 8).
Financing Activities
Cash flows from financing activities in the first half of 2003 decreased by
$1,277 million when compared to the first half of 2002 ($(239) million compared
to $1,038 million during 2003 and 2002, respectively), primarily as the result
of AEP's retirement and restructuring of its short-term and long-term debt
during 2003. During the first half of 2003, AEP was able to retire $4,393
million of debt ($2,675 million short-term and $1,718 million of long-term) and
increase available cash primarily through the issuance of long-term financing
($3,546 million), issuance of common stock ($1,177 million) and the generation
of cash from operating activities.
Financing Activity
Common Stock Offering
On February 27, 2003, we priced our offering of 50 million shares of common
stock at a public offering price of $20.95 per share. We granted the
underwriters an option to purchase an additional 7.5 million shares of common
stock to cover over allotments. The underwriters exercised their over allotment
option to purchase an additional 6 million shares. The net proceeds of
approximately $1.1 billion from the sale of these securities were used to reduce
debt and for other corporate purposes.
Debt
In May 2003, a third party exercised its option to call $250 million of 5.50%
putable callable notes, issued by us in May 2001, for purchase and remarketing.
On May 15, 2003, we issued $300 million of 5.25% senior notes due 2015, a
portion of which was an exchange for the $250 million putable callable notes due
in 2003.
In March 2003, we 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 of $494 million from the offering were used to repay or redeem
current maturities of long-term debt and for other corporate purposes.
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
proceeds from the bond issuances were used to repay the bank facility due to
mature in April 2003, short-term debt and for other corporate purposes.
Also, see Note 15 for further information on financing activities.
Significant Factors
- -------------------
Possible Divestitures
We have a strong commitment to continually evaluate the need to reallocate
resources to areas that effectively match investments with our business
strategy, provide greater potential for financial returns, and to dispose of
investments that no longer meet these principles.
We are seeking to divest assets that consist of domestic and international
unregulated generation, gas pipelines, a coal business and a communications
business. In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generating capacity in Texas to establish a market price for
calculation of stranded cost (see Note 7). Also in the second quarter 2003, we
hired an advisor to evaluate our coal business which has resulted in receipt of
non-binding bids which are currently being evaluated. In the third quarter of
2003, management hired advisors to review business options regarding various
components of our Gas Operations investment. This review is expected to be
completed before year-end and will include an analysis of alternatives for
packaging the business for sale along with review of our investment in gas
operations for impairment of value, including related goodwill of approximately
$300 million. Management is unable to determine the extent of an impairment, if
any, until such evaluation is complete. Management continues to have periodic
discussions with various parties on business alternatives for certain of our
other non-core investments.
The ultimate timing for a disposition of one or more of these assets will depend
upon market conditions and the value of any buyer's proposal. If we choose to
dispose of these assets, we may realize non-recurring losses in the aggregate
that could have a material impact on our results of operations, cash flows and
financial condition.
Corporate Separation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), we have filed with the FERC and SEC seeking approval to
separate our regulated and unregulated operations. With the changes in our
business strategy, in response to energy market and business conditions,
management continues to evaluate corporate separation plans, including
determining whether legal corporate separation is appropriate in jurisdictions
where it is not legally required.
RTO Formation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), the FERC's AEP-CSW merger approval and many of the
settlement agreements with the state regulatory commissions to approve the
AEP-CSW merger required the transfer of functional control of the subsidiaries'
transmission systems to RTOs.
In May 2002, we announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to be
negotiated. In July 2002, FERC issued an order accepting our decision to
participate in PJM, subject to specified conditions. AEP and other parties
continued to work on the resolution of those conditions.
In December 2002, our subsidiaries, which operate in the states of Indiana,
Kentucky, Ohio and Virginia, filed for state regulatory commission approval of
their plans to transfer functional control of their transmission assets to PJM
based on statutory or regulatory requirements in those states. In July 2003, the
KPSC ruled in part that we had failed to prove the benefit of our PJM RTO
membership to Kentucky retail customers and denied our request for approval of
transfer of functional control to PJM. Management plans to seek a rehearing.
Proceedings in the other states remain pending.
In February 2003, the Virginia Legislature enacted legislation, which the
Governor of Virginia signed, that prohibited the transfer of transmission assets
in its jurisdiction to an RTO, until at least July 2004 and then only with
Virginia SCC approval.
In April 2003, FERC approved our transfer of functional control of the AEP East
companies' transmission system to PJM. FERC also accepted our proposed rates for
joining PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings. Settlement discussions continue on certain rate
matters.
AEP West companies are members of ERCOT or the SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and the SPP. Our
SPP companies are also regulated by state public utility commissions. The
Louisiana and Arkansas commissions filed responses to the FERC's RTO order
indicating that additional analysis was required. Subsequently, the proposed
SPP/MISO combination was terminated. Regulatory activities concerning various
RTO issues are ongoing in Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory
actions and proceedings or their impact on the timing and operation of RTOs, our
transmission operations or results of operations and cash flows.
Industry Restructuring
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), restructuring and customer choice are in place in four
of the eleven state retail jurisdictions in which our electric utility companies
operate. Restructuring legislation generally provides for a transition from
cost-based rate regulation of bundled electric service to customer choice and
market pricing for the supply of electricity. The status of our transition
plans, regulatory issues and proceedings and accounting issues in the state
regulatory jurisdictions impacted by restructuring and customer choice is
presented in Note 7.
Nuclear Plant Outages
In April 2003, engineers at STP, during inspections conducted regularly as part
of refueling outages, found wall cracks in two bottom mounted instrument guide
tubes of STP Unit 1. These cracks have been repaired and the unit is expected to
return to service in late summer. Our share of the direct cost of repair was
approximately $6 million through June 30, 2003. STP officials are working
closely with the NRC to safely return the unit to service. We have commitments
to provide power to customers during the outage. Therefore, we will be subject
to fluctuations in the market prices of electricity and purchased replacement
energy could be a significant cost.
In April 2003, both units of Cook Plant were taken offline due to an influx of
fish in the plant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of damage caused by the fish
intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to
service in June following completion of a scheduled refueling outage.
Litigation
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal
Proceedings",AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in
litigation since 1999 regarding generating plant emissions under the Clean Air
Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and
eleven unaffiliated utilities made modifications to generating units at
coal-fired generating plants in violation of the Clean Air Act. Federal EPA
filed complaints against our 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.
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
is 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. See Note
8 for further discussion.
NOx Reductions
Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act 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 the rules is May 31,
2004.
The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo
and TCC. The compliance requirements began in May 2003 for TCC and begin in May
2005 for SWEPCo.
We are installing selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions on certain units to comply with these rules.
Our estimates indicate that compliance with the rules could result in required
capital expenditures in a range of approximately $1.3 billion to $1.7 billion
for the AEP System of which $976 million has been spent through June 30, 2003.
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 or operating costs for 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 8 for further discussion.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corporation and its subsidiaries which is 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.
Management believes that our entities have the right to utilize offsetting
receivables and payables and related collateral across various Enron entities by
offsetting 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. In this regard,
Enron sent to AEPES a demand for payment of approximately $138 million relating
to AEPES' termination of trading contracts. 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 8 for further discussion.
Bank of Montreal Claim
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit against BOM claiming BOM had acted contrary to industry practice in
calculating termination and liquidation amounts and that BOM had acknowledged in
March 2003 that it owed us approximately $68 million. Alternatively, we are
claiming that BOM owes us approximately $45 million. Although management is
unable to predict the outcome of this matter, it is not expected to have a
material impact on results of operations, cash flows or financial condition.
Arbitration of Williams Claim
In 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
AEP and Williams settled the dispute with AEP paying $90 million to Williams in
June 2003. The resolution of this matter had an immaterial impact on results of
operations as we had accrued the amount paid. See Note 8 for further discussion.
Arbitration of PG&E Energy Trading, LLC Claim
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11
million to PGET. The settlement payment did not have a material impact on
results of operations, cash flows or financial condition as the payment
approximated our recorded liability.
Energy Market Investigations
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), AEP and other energy market participants received data
requests, subpoenas and requests for information from the FERC, the SEC, the
PUCT, the U.S. Commodity Futures Trading Commission, the U.S. Department of
Justice and the California attorney general during 2002. Management responded to
the inquires and provided the requested information and has continued to respond
to supplemental data request in 2003.
In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC seeking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.
Management cannot predict what, if any action, any of these governmental
agencies may take with respect to these matters.
Shareholders' Litigation
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against us, certain
executives, members of the Board of Directors and certain investment banking
firms. These cases are in the initial pleading stage. We intend to vigorously
defend against these actions. See Note 8 for further discussion.
California Lawsuit
In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. We intend to vigorously
defend against this action. See Note 8 for further discussion.
Snohomish Settlement
In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract and paid $59 million to us. As a result of the contract
termination, we reversed $69 million of unrealized mark-to-market gains
previously recorded, resulting in a $10 million pre-tax loss.
Other Litigation
We continue to be involved in certain other legal matters discussed in the 2002
Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003).
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Critical Accounting Policies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of the estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the impact of new accounting pronouncements.
New Accounting Pronouncements
See Note 2 for a discussion of significant accounting policies and new
accounting pronouncements.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
As a major power producer and marketer of wholesale electricity and natural gas,
we have certain market risks inherent in our business activities. These risks
include commodity price risk, interest rate risk, foreign exchange risk and
credit risk. They represent the risk of loss that may impact us due to changes
in the underlying market prices or rates.
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.
AEP has actively participated in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around energy
trading contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. Recently the CCRO adopted
disclosure standards for energy contracts to improve clarity, understanding and
consistency of information reported. Implementation of the new disclosures is
voluntary. AEP supports the work of the CCRO and has embraced the new
disclosures. The following tables provide information on AEP's risk management
activities.
Roll-Forward of Mark-to-Market Risk Management Contract Net Assets
This table provides detail on changes in AEP's mark-to-market (MTM) net asset
or liability balance sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2003
Utility Gas UK
Operations Operations Operations Consolidated
---------- ---------- ---------- ------------
(in millions)
Beginning Balance December 31, 2002 $360 $(155) $ 45 $250
-----------------------------------
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (139) 63 8 (68)
Fair Value of New Contracts When Entered
Into During the Period (b) - - - -
Net Option Premiums Paid/(Received) (c) 1 53 (7) 47
Change in Fair Value Due to Valuation Methodology
Changes - 1 - 1
Effect of 98-10 Rescission (19) 1 (14) (32)
Changes in Fair Value of Risk Management
Contracts (d) 57 (31) (12) 14
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 27 - - 27
---- ----- ---- ----
Ending Balance June 30, 2003 $287 $ (68) $ 20 $239
==== ===== ==== ====
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
includes realized gains from risk management contracts and related
derivatives that settled during 2003 that were entered into prior to
2003.
(b) The "Fair Value of New Contracts When Entered Into During the
Period" represents the fair value of long-term contracts entered
into with customers during 2003. 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 associated with the delivery
location.
(c)"Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and unexpired
option contracts that were entered into in 2003.
(d)"Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(e)"Change in Fair Value of Risk Management Contracts Allocated to
Regulated Jurisdictions" relates to the net gains (losses) of those
contracts that are not reflected in the Consolidated Statements of
Operations. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
Detail on MTM Risk Management Contract
Net Assets
As of June 30, 2003
Utility Gas UK
Operations Operations Operations Consolidated
---------- ---------- ---------- ------------
(in millions)
Current Assets $ 365 $ 451 $ 166 $ 982
Non Current Assets 418 316 91 825
----- ----- ----- -------
Total MTM Energy Assets $ 783 $ 767 $ 257 $ 1,807
----- ----- ----- -------
Current Liabilities $(281) $(532) $(156) $ (969)
Non Current Liabilities (215) (303) (81) (599)
----- ----- ----- -------
Total MTM Risk Management Contract Liabilities $(496) $(835) $(237) $(1,568)
----- ----- ----- -------
Total MTM Risk Management Contract Net Assets $ 287 $ (68) $ 20 239
===== ===== =====
Net Non-Trading Related Derivative Contracts (114)
Net Fair Value of Risk Management and Derivative
Contracts $ 125
=======
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information.
o The source of fair value used in determining the carrying amount of AEP's
total MTM asset or liability (external sources or modeled internally)
o The maturity, by year, of AEP's net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of June 30, 2003
Remainder After
Utility Operations: 2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in millions)
Prices Actively Quoted - Exchange Traded
Contracts $ (4) $ (6) $ (3) $(2) $ - $ - $(15)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 46 59 23 19 6 - 153
Prices Based on Models and Other
Valuation Methods (b) 19 16 14 23 24 53 149
----- ---- ---- --- --- --- ----
Total $ 61 $ 69 $ 34 $40 $30 $53 $287
===== === ==== === === === ====
Gas Operations:
Prices Actively Quoted - Exchange
Traded Contracts (a) $(119) $ 90 $ 9 $ - $ - $ - $(20)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) 119 16 - - - - 135
Prices Based on Models and Other
Valuation Methods (b) (144) (32) (12) 5 8 (8) (183)
----- ---- ---- --- --- --- -----
Total $(144) $ 74 $ (3) $ 5 $ 8 $(8) $ (68)
===== ==== ==== === === === =====
UK Operations:
Prices Actively Quoted - Exchange Traded
Contracts (a) $ - $ - $ - $ - $ - $ - $ -
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 14 6 8 (3) - - 25
Prices Based on Models and Other
Valuation Methods (b) (2) - (5) - 2 - (5)
----- ---- ---- --- --- --- ----
Total $ 12 $ 6 $ 3 $(3) $ 2 $ - $ 20
===== ==== ==== === === === ====
Consolidated:
Prices Actively Quoted - Exchange Traded
Contracts $(123) $ 84 $ 6 $(2) $ - $ - $(35)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) 179 81 31 16 6 - 313
Prices Based on Models and Other
Valuation Methods (b) (127) (16) (3) 28 34 45 (39)
----- ---- ---- --- --- --- ----
Total $ (71) $149 $ 34 $42 $40 $45 $239
===== ==== ==== === === === ====
(a) Prices provided by other external sources - Reflects information obtained
from over-the-counter brokers, industry services, or multiple-party on-line
platforms.
(b) Modeled - In the absence of pricing information from external sources,
modeled information is derived using valuation models developed by the
reporting entity, reflecting when appropriate, option pricing theory,
discounted cash flow concepts, valuation adjustments, etc. and may require
projection of prices for underlying commodities beyond the period that prices
are available from third-party sources. In addition, where external pricing
information or market liquidity are limited, such valuations are
classified as modeled.
The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in the preceding table varies by market. The
following table reports an estimate of the maximum tenors of the liquid portion
of each energy market.
Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of June 30, 2003
Domestic Tenor
-------- (in months)
Natural Gas Forward Purchases and Sales
NYMEX Henry Hub Gas 66
Gas East - Northeast, Mid-continent
Gulf Coast, Texas 12
Gas West - Permian Basin, San Juan,
Rocky Mtns, Kern, Cdn Border(Sumas),
Malin, PGE Citygate, AECO 12
Power (Peak) Forward Purchases and Sales
Power East - Cinergy 42
Power East - PJM 42
Power East - NYPP 30
Power East - NEPOOL 18
Power East - ERCOT 18
Power East - TVA 0
Power East - Com Ed 18
Power East - Entergy 18
Power West - PV, NP15,SP15,MidC,Mead 54
Peak Power Volatility
(Options) Cinergy 18
OffPeak Power Volatility All Regions 0
Natural Gas
Liquids 11
WTI Crude 48
Emissions 30
Coal 30
International
Power United Kingdom 36
Coal Forward Purchases and Sales United Kingdom 15
Financial Transactions (Swaps) Europe 33
Cash Flow Hedges Included in Accumulated Other Comprehensive Income on the
Balance Sheet
AEP employs fair value hedges and cash flow hedges to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. AEP does not hedge all interest rate risk.
AEP employs forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. International subsidiaries use currency swaps to hedge exchange rate
fluctuations of debt denominated in foreign currencies. AEP does not hedge all
foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges AEP has in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the
table does not provide an all-encompassing picture of AEP's hedging activity).
The table further indicates what portions of these hedges are expected to be
reclassified into the income statement in the next 12 months. The table also
includes a roll-forward of the AOCI balance sheet account, providing insight
into the drivers of the changes (new hedges placed during the period, changes
in value of existing hedges and roll off of hedges).
Information on energy merchant activities is presented separately from interest
rate, foreign currency risk management activities and other hedging activities.
In accordance with GAAP, all amounts are presented net of related income taxes.
Cash Flow Hedges included in Accumulated Other Comprehensive Income
On the Balance Sheet as of June 30, 2003
Accumulated Other Portion Expected
Comprehensive to Be Reclassified
Income to Earnings During
(Loss) After Tax(a) Next 12 Months (b)
------------------ ------------------
(in millions)
Power $ (92) $(44)
Foreign Currency (10) (8)
Interest Rate (14) (5)
----- ----
Consolidated $(116) $(57)
===== ====
Total Other Comprehensive Income Activity
Six Months Ended June 30, 2003
Foreign AEP
Power Currency Interest Rate Consolidated
----- -------- ------------- ------------
(in millions)
Accumulated OCI, December 31, 2002 $ (3) $(1) $(12) $ (16)
----------------------------------
Changes in Fair Value (c) (89) (9) (3) (101)
Reclassifications from OCI to Net
Income (d) - - 1 1
---- ---- ---- -----
Accumulated OCI Derivative Loss June 30, 2003 $(92) $(10) $(14) $(116)
==== ==== ==== =====
(a) Accumulated other comprehensive income (loss) after tax - Gains/losses
are net of related income taxes that have not yet been included in the
determination of net income; reported as a separate component of
shareholders' equity on the balance sheet.
(b) Portion expected to be reclassified to earnings during the next 12
months - Amount of gains or losses (realized or unrealized) from
derivatives used as hedging instruments that have been deferred and
are expected to be reclassified into net income during the next 12
months at the time the hedged transaction affects net income.
(c) Changes in fair value - Changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of
related income taxes.
(d) Reclassifications from AOCI to net income - Gains or losses from
derivatives used as hedging instruments in cash flow hedges that were
reclassified into net income during the reporting period. Amounts are
reported net of related income taxes above.
Credit Risk
AEP limits credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continuing to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met AEP's internal credit rating criteria will we extend unsecured credit.
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. AEP's independent analysis, in conjunction with the rating
agencies 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.
AEP has risk management contracts with numerous counterparties. Since AEP's open
risk management contracts are valued based on changes in market prices of the
related commodities, AEP's exposures change daily. AEP believes that credit and
market exposures with any one counterparty is not material to AEP's financial
condition at June 30, 2003. At June 30, 2003 AEP's credit exposure net of credit
collateral to sub investment grade counterparties was approximately 10%,
expressed in terms of net MTM assets and net receivables. 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
June 30, 2003 the following table approximates counterparty credit quality and
exposure for AEP based on netting across AEP entities, commodities and
instruments:
Number of Net Exposure of
Counterparty Exposure Before Credit Net Counterparties Counterparties
Credit Quality: Credit Collateral Collateral Exposure > 10% > 10%
-------------- ----------------- ---------- -------- ----- -----
(in millions)
Investment Grade $1,112 $143 $ 969 1 $131
Split Rating 37 - 37 1 36
Non-Investment Grade 191 122 69 3 33
No External Ratings:
Internal Investment
Grade 322 3 319 2 126
Internal Non-Investment
Grade 143 58 85 1 13
------ ---- ------ ----
Total $1,805 $326 $1,479 $339
====== ==== ====== ====
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
Generation Plant Hedging Information
This table provides information on operating measures regarding the proportion
of output of AEP's generation facilities (based on economic availability
projections) economically hedged. This information is forward-looking and
provided on a prospective basis through December 31, 2005. Please note that this
table is point-in time estimates, subject to changes in market conditions and
AEP decisions on how to manage operations and risk.
Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2003
2003 2004 2005
---- ---- ----
Estimated Plant Output Hedged (a) 94% 90% 83%
(a) Estimated Plant Output Hedged - Represents the portion of megawatt-hours of
future generation/production for which AEP has sales commitments to customers.
VaR Associated with Energy Trading Contracts
AEP uses a risk measurement model which calculates Value at Risk (VaR) to
measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is
based on the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes 95% confidence level, a one-day
holding period and a one-tailed distribution. Based on this VaR analysis, at
June 30, 2003 a near term typical change in commodity prices is not expected to
have a material effect on AEP's results of operations, cash flows or financial
condition. The following table shows the end, high, average, and low market risk
as measured by VaR year-to-date:
VaR Model
---------
June 30, December 31,
2003 2002
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$5 $19 $ 7 $5 $5 $24 $12 $4
The High VaR for 2003 occurred in late February 2003 during a period when
natural gas and power prices experienced high levels and extreme volatility.
Within a few days the VaR returned to levels more representative of the average
VaR for the year.
The AEP VaR model results are adjusted using standard statistical treatments to
calculate the CCRO VaR reporting metrics listed below. The adjustments are made
to take the AEP model results from a one-day 95% confidence level to a ten-day
99% confidence level. The AEP VaR model's performance has not been evaluated
for its accuracy at calculating VaR using the CCRO VaR Metrics assumptions.
CCRO VaR Metrics
Average for
End of Year-to-Date High for Low for
June 30, 2003 2003 Year-to-Date 2003 Year-to-Date 2003
-------------- ----------- ------------------ -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period, Two-Tailed $20 $27 $71 $17
99% Confidence Level, One-Day
Holding Period, Two-Tailed $ 8 $11 $30 $ 7
AEP utilizes 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, a one year holding period and a one-tailed distribution. The
volatilities and correlations were based on three years of daily 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 $1,217
million at June 30, 2003 and $527 million at December 31, 2002. AEP would not
expect to liquidate its entire debt portfolio in a one year holding period,
therefore a near term change in interest rates should not materially affect
results of operations or consolidated financial position.
AEP is exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by settlement agreements in Michigan
and West Virginia or capped in Indiana. To the extent the fuel supply of the
generating units in these states is not under fixed price long-term contracts
AEP is subject to market price risk. AEP continues to be protected against
market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana,
Kentucky, Virginia and the SPP area of Texas.
AEP employs 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. AEP engages in risk management of
electricity, gas and to a lesser degree other commodities, principally coal
and freight. As a result, AEP is subject to price risk. The amount of risk
taken is controlled by risk management operations and AEP's Chief Risk
Officer and his staff. When the risk from energy 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.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
2003 2002 2003 2002
---- ---- ---- ----
REVENUES:
Utility Operations $2,628 $2,660 $5,401 $4,918
Gas Operations 829 670 1,931 1,103
U.K. Operations and Other 212 251 417 552
------ ------ ------ ------
TOTAL REVENUES 3,669 3,581 7,749 6,573
------ ------ ------ ------
EXPENSES:
Fuel for Electric Generation 850 631 1,510 1,252
Purchased Electricity for Resale 215 78 420 107
Purchased Gas for Resale 708 712 1,857 1,066
Maintenance and Other Operation 981 1,199 1,944 2,205
Depreciation and Amortization 336 351 651 683
Taxes Other Than Income Taxes 157 183 345 374
------ ------ ------ ------
TOTAL EXPENSES 3,247 3,154 6,727 5,687
------ ------ ------ ------
OPERATING INCOME 422 427 1,022 886
OTHER INCOME 86 49 204 61
OTHER EXPENSE 57 6 102 26
LESS:INTEREST 198 196 403 391
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 3 3 6 5
MINORITY INTEREST IN FINANCE SUBSIDIARY 8 9 17 18
------ ------ ------ ------
INCOME BEFORE INCOME TAXES 242 262 698 507
INCOME TAXES 60 104 260 190
------ ------ ------ ------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT 182 158 438 317
Discontinued Operations (net of tax) (7) (96) (16) (74)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX):
Goodwill and Other Intangible Assets - - - (350)
Accounting for Risk Management Contracts - - (49) -
Asset Retirement Obligation - - 242 -
------ ------ ------ ------
NET INCOME (LOSS) $ 175 $ 62 $ 615 $ (107)
====== ====== ====== ======
AVERAGE NUMBER OF SHARES OUTSTANDING 395 326 376 324
=== === === ===
EARNINGS (LOSS) PER SHARE:
Income Before Discontinued Operations And
Cumulative Effect of Accounting Changes $ 0.46 $ 0.48 $ 1.17 $ 0.98
Discontinued Operations (0.02) (0.29) (0.04) (0.23)
Cumulative Effect of Accounting Changes - - 0.51 (1.08)
------ ------ ------ ------
EARNINGS (LOSS) PER SHARE (BASIC
AND DILUTIVE) $ 0.44 $ 0.19 $ 1.64 $(0.33)
====== ====== ====== ======
CASH DIVIDENDS PAID PER SHARE $ 0.35 $ 0.60 $ 0.95 $ 1.20
====== ====== ====== ======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in millions)
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 1,176 $ 1,213
Accounts Receivable (net) 1,685 1,740
Fuel, Materials and Supplies 1,178 1,166
Risk Management Assets 1,010 1,012
Other 883 935
------- -------
TOTAL CURRENT ASSETS 5,932 6,066
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,575 17,031
Transmission 5,962 5,882
Distribution 9,709 9,573
Other (including gas, coal mining and
nuclear fuel) 3,926 3,965
Construction Work in Progress 1,272 1,406
------- -------
Total Property, Plant and Equipment 38,444 37,857
Accumulated Depreciation and Amortization 16,031 16,173
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 22,413 21,684
------- -------
REGULATORY ASSETS 2,669 2,688
------- -------
SECURITIZED TRANSITION ASSETS 716 735
------- -------
INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 283
------- -------
GOODWILL 396 396
------- -------
ASSETS HELD FOR SALE 219 292
------- -------
LONG-TERM RISK MANAGEMENT ASSETS 836 819
------- -------
OTHER ASSETS 1,895 1,783
------- -------
TOTAL ASSETS $35,359 $34,746
======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2003 December 31, 2002
------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 1,860 $ 2,030
Short-term Debt 567 3,164
Long-term Debt Due Within One Year 1,020 1,633
Risk Management Liabilities 1,055 1,113
Other 1,739 1,802
------- -------
TOTAL CURRENT LIABILITIES 6,241 9,742
------- -------
LONG-TERM DEBT 10,934 8,487
------- -------
EQUITY UNIT SENIOR NOTES 376 376
------- -------
LONG-TERM RISK MANAGEMENT LIABILITIES 666 481
------- -------
DEFERRED INCOME TAXES 4,068 3,916
------- -------
DEFERRED INVESTMENT TAX CREDITS 440 455
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 866 770
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 180 185
------- -------
LIABILITIES HELD FOR SALE 103 142
------- -------
OTHER NONCURRENT LIABILITIES 2,074 1,903
------- -------
COMMITMENTS AND CONTINGENCIES (Note 8)
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 533 759
------- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 144 145
------- -------
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2003 2002
---- ----
Shares Authorized. . . 600,000,000 600,000,000
Shares Issued. . . . . 404,001,845 347,835,212
(8,999,992 shares were held in treasury at June 30, 2003
and December 31, 2002) 2,626 2,261
Paid-in Capital 4,182 3,413
Accumulated Other Comprehensive Income (Loss) (670) (609)
Retained Earnings 2,275 1,999
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,413 7,064
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $35,359 $34,746
======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2003 2002
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income (Loss) $ 615 $(107)
Plus: Discontinued Operations 16 74
------- ------
Income from Continuing Operations 631 (33)
Adjustments for Noncash Items:
Depreciation and Amortization 651 687
Deferred Income Taxes 51 (106)
Deferred Investment Tax Credits (16) (10)
Cumulative Effect of Accounting Changes (193) 350
Amortization of Deferred Property Taxes - 35
Amortization of Cook Plant Restart Costs 20 20
Mark to Market of Risk Management Contracts (48) 207
Changes in Certain Current Assets and Liabilities:
Accounts Receivable, net 46 (919)
Fuel, Materials and Supplies (46) 250
Accrued Utility Revenues 51 (176)
Prepayments and Other 93 (411)
Accounts Payable (177) 343
Taxes Accrued 36 (14)
Interest Accrued 11 39
Over/Under Fuel Recovery 85 (35)
Change in Other Assets (209) (325)
Change in Other Liabilities (188) 195
------ -----
Net Cash Flows From Operating Activities 798 97
------ -----
INVESTING ACTIVITIES:
Construction Expenditures (649) (784)
Proceeds from Sale of Assets 41 -
Other 12 -
------ -----
Net Cash Flows Used For Investing Activities (596) (784)
------ -----
FINANCING ACTIVITIES:
Issuance of Common Stock 1,177 656
Issuance of Long-term Debt 3,546 1,786
Issuance of Equity Unit Senior Notes - 334
Change in Short-term Debt, net (2,675) (980)
Retirement of Long-term Debt (1,718) (371)
Retirement of Preferred Stock (2) -
Retirement of Minority Interest (225) -
Dividends Paid on Common Stock (342) (387)
------ -----
Net Cash Flows From (Used For) Financing Activities (239) 1,038
------ -----
Effect of Exchange Rate Change on Cash - (14)
------ -----
Net Increase (Decrease) in Cash and Cash Equivalents (37) 337
Cash and Cash Equivalents at Beginning of Period 1,213 224
------ -----
Cash and Cash Equivalents at End of Period $1,176 $ 561
====== =====
Net Increase in Cash and Cash Equivalents from Discontinued Operations $ 11 $ 19
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 8 108
------ -----
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 19 $ 127
====== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $364 million and $335
million and for income taxes was $155 million and $307 million in 2003 and 2002,
respectively. Noncash acquisitions under capital leases were $1 million in 2003
and $2 million in 2002.
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT