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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 SEPTEMBER 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 October 31, 2003 was 395,007,320.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2003
Page
----
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-19
Consolidated Financial Statements A-20 - A-25
Notes to Consolidated Financial Statements A-26 - A-57
AEP Generating Company:
Management's Narrative Financial Discussion and Analysis B-1
Financial Statements B-2 - B-5
AEP Texas Central Company and Subsidiary:
Management's Financial Discussion and Analysis C-1 - C-8
Consolidated Financial Statements C-9 - C-12
AEP Texas North Company:
Management's Narrative Financial Discussion and Analysis D-1 - D-6
Financial Statements D-7 - D-11
Appalachian Power Company and Subsidiaries:
Management's Financial Discussion and Analysis E-1 - E-7
Consolidated Financial Statements E-8 - E-12
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-6
Consolidated Financial Statements G-7 - G-11
Kentucky Power Company:
Management's Narrative Financial Discussion and Analysis H-1 - H-6
Financial Statements H-7 - H-11
Ohio Power Company Consolidated:
Management's Financial Discussion and Analysis I-1 - I-7
Consolidated Financial Statements I-8 - I-12
Public Service Company of Oklahoma:
Management's Narrative Financial Discussion and Analysis J-1 - J-5
Financial Statements J-6 - J-10
Southwestern Electric Power Company Consolidated:
Management's Financial Discussion and Analysis K-1 - K-6
Consolidated Financial Statements K-7 - K-11
Notes to Respective Financial Statements L-1 - L-24
Item 4. Controls and Procedures M-1
Part II. OTHER INFORMATION
Item 1. Legal Proceedings N-1
Item 5. Other Information N-1
Item 6. Exhibits and Reports on Form 8-K N-1
(a) Exhibits: Exhibit 12 Exhibit 31.1
Exhibit 31.2 Exhibit 32.1 Exhibit
32.2
(b) Reports on Form 8-K
SIGNATURE 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 and consolidated affiliates.
AEP Credit AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated domestic electric utility companies.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCo.
AEPES AEP Energy Services, Inc., a subsidiary of AEPR.
AEPR AEP Resources, Inc.
AEP System or the System The American Electric Power System, an integrated electric utility system, owned and
operated by AEP's electric utility subsidiaries.
AEPSC American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP 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.
Amos Plant John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APB 18 Accounting Principles Board Opinion Number 18: The Equity Method of Accounting for
Investments in Common Stock.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission Arkansas Public Service Commission.
Buckeye Buckeye Power, Inc., an unaffiliated corporation.
COLI Corporate owned life insurance program.
Cook Plant The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
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, an AEP subsidiary.
LPSC Louisiana Public Service Commission.
Michigan Legislation The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool AEP System's Money Pool.
MPSC Michigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx Nitrogen oxide.
NOx Rule A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies operate.
NRC Nuclear Regulatory Commission.
OCC The Corporation Commission of the State of Oklahoma.
Ohio Act The Ohio Electric Restructuring Act of 1999.
Ohio EPA Ohio Environmental Protection Agency.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
PJM Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB Price-to-Beat.
PUCO The Public Utilities Commission of Ohio.
PUCT The Public Utility Commission of Texas.
PUHCA Public Utility Holding Company Act of 1935, as amended.
PURPA The Public Utility Regulatory Policies Act of 1978.
RCRA Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
REP Retail Electric Provider.
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 Obligations.
-------------------------------------------
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.
----------
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.
Tenor Maturity of a contract.
Texas Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC AEP Texas North Company, an AEP electric utility subsidiary.
TVA Tennessee Valley Authority.
U.K. The United Kingdom.
VaR Value at Risk, a method to quantify risk exposure.
Virginia SCC Virginia State Corporation Commission.
WVPSC Public Service Commission of West Virginia.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
Zimmer Plant William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
FORWARD-LOOKING INFORMATION
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 including requirements for
reduced emissions of sulfur, nitrogen, carbon and other substances.
o Pending and future rate cases and negotiations.
o Oversight and/or investigation of the energy sector or its
participants.
o Our ability to successfully control costs.
o The success of 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.
o The economic climate and growth in our service territory and changes
in market
demand and demographic patterns.
o Inflationary trends.
o Accounting pronouncements periodically issued by accounting
standard-setting bodies.
o The performance of AEP's pension plan.
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 third quarter and nine months ended September 30, 2003 and 2002
were as follows:
Third Quarter Nine Months Ended
------------- -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in millions)
Utility Operations $372 $405 $886 $846
Investments - Gas Operations (20) 5 (59) (75)
Investments - UK Operations (51) (5) (88) 6
Investments - Other (44) (19) (44) (74)
----- ----- ----- -----
Continuing Operations 257 386 695 703
Discontinued Operations - 39 (16) (35)
Cumulative Effect of
Accounting Changes - - 193 (350)
----- ----- ----- -----
Total Net Income $257 $425 $872 $318
===== ===== ===== =====
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Our Net Income for the third quarter of 2003 is discussed below according to the
operating segments listed above. Income from Continuing Operations (or Income
Before Discontinued Operations and Cumulative Effect of Accounting Changes) for
the quarter was negatively affected by the weather, weak economy and the
availability of electric generation. Third quarter 2003 Net Income was $257
million or $0.65 per share compared to $425 million or $1.25 per share in 2002.
In March 2003 common stock was issued which caused $0.11 per share dilution in
the current quarter.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Our Net Income for Nine Months Ended is discussed below according to the
operating segments listed above. Income from Continuing Operations (or Income
Before Discontinued Operations and Cumulative Effect of Accounting Changes) was
negatively affected by the weather, weak economy and the availability of
electric generation. 2003 Net Income of $872 million or $2.28 per share includes
a loss on discontinued operations of $16 million (net of tax) (see Note 8), $242
million (net of tax) of Income from the Cumulative Effect of Accounting Changes
in the first quarter resulting from the implementation of SFAS 143 (see Note 3),
partially offset by $49 million (net of tax) of Loss from the Cumulative Effect
of Accounting Changes in the first quarter resulting from the implementation of
EITF 02-3 (see Note 3). 2002 Net Income of $318 million or $0.97 per share
includes a loss on discontinued operations of $35 million (net of tax) (see Note
8) and a $350 million (net of tax) charge for the implementation of SFAS 142
(see Note 3). A common stock issuance in March 2003 caused a $0.37 per share
dilution in the nine-month period.
Utility Operations
Summary of Selected Sales Data
For Utility Operations
Third Quarter Nine Months Ended
------------- -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in millions of KWH)
ENERGY SUMMARY
Retail
Residential 12,606 13,405 34,813 35,781
Commercial 10,341 10,118 28,082 27,797
Industrial 12,932 13,154 38,620 40,287
Miscellaneous 829 891 2,258 2,059
------- ------- -------- --------
Total 36,708 37,568 103,773 105,924
------- ------- -------- --------
Wholesale 22,093 20,938 56,385 53,393
------- ------- -------- --------
WEATHER SUMMARY (in degree days)
EASTERN REGION
Actual - Heating 78 22 3,444 2,910
Normal - Heating 80 80 3,298 3,340
Actual - Cooling 618 916 782 1,269
Normal - Cooling 708 701 1,002 992
WESTERN REGION
Actual - Heating - - 839 789
Normal - Heating - - 840 829
Actual - Cooling 1,386 1,438 1,941 2,063
Normal - Cooling 1,398 1,396 1,919 1,910
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Net Income for Utility Operations, our core business, decreased by $33 million
due to a decrease in operating income.
Our operating income decreased in the third quarter primarily due to:
o A reduction in pre-tax earnings of $89 million for the loss of
contributions from our two Texas retail electricity providers that we
sold to Centrica in December 2002. The demand from our two Texas retail
providers was replaced, in part, with a power supply contract with
Centrica that extends through 2004. Our Texas supply margins also
decreased due to an outage at our STP nuclear plant and the related
higher costs of replacement power. Our 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 Retail margins from our regulated integrated utilities, which reduced
pre-tax earnings by $71 million due to lower demand from the combined
impact of weather and a continued weak economy.
o Reduced demand in our Ohio Companies resulting from mild weather and
economic pressures on industrial customers, which reduced pre-tax
earnings by $15 million.
Our operating income decrease was partially offset by:
o Pre-tax earnings from our Texas distribution operations (Texas wires),
which increased $19 million primarily from the $61 million non-cash
earnings associated with the capacity auction true-up in Texas. The
provisions for stranded cost recovery in Texas recognize a regulatory
asset or liability for the difference between the actual price received
from the state-mandated auction of 15% of generation capacity and the
earlier estimate of market price derived by a PUCT model. We filed a
plan of divestiture with the PUCT in December 2002, enabling us to
record a regulatory asset associated with stranded cost recovery. Our
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, which increased $76 million in the
current quarter due to low cost generation that was available because
of weather-related reductions in retail demand, favorable power
optimization and higher peak prices in ECAR.
o A $13 million decrease in Taxes Other Than Income Taxes primarily
caused by reduced gross receipts tax due to the sale of the Texas REPs.
o A $15 million decrease in Maintenance and Other Operation expenses due
to ongoing efforts to reduce costs despite incurring higher storm
damage repair costs in the current quarter.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Net Income for Utility Operations increased $40 million due primarily to an $85
million increase in operating income partially offset by an increase in
nonoperating expenses.
Our operating income increased primarily due to:
o Texas wires pre-tax earnings, which increased $137 million
primarily from $169 million in non-cash earnings associated
with the capacity auction true-up in Texas.
o Pre-tax earnings for systems sales, transmission revenue and other
wholesale transactions, which increased $141 million due to low cost
generation that was available because of weather-related reductions in
retail demand, favorable power optimization, higher peak prices and
increased sales in ECAR. In addition, we experienced higher third-party
transmission volumes and recognized a loss on the settlement of a
long-term contract with the Public Utility District No. 1 of Snohomish
County, Washington (see Significant Factors - Litigation).
o Other operating revenue, which increased $29 million due to associated
business development in Western non-regulated companies for the
construction of transmission lines, services fees, pole attachments and
transmission rentals.
o Maintenance and Other Operation expense, which decreased $39
million due to ongoing efforts to reduce costs despite severe storm
damage in the Midwest.
o A $28 million decrease in Taxes Other Than Income Taxes primarily
caused by reduced gross receipts tax due to the sale of the Texas REPs.
o Depreciation and Amortization, which decreased by $28 million due to
the change in accounting for asset retirement obligations as mandated
by SFAS 143. This decrease, however, is offset by similar increases in
Maintenance and Other Operation expenses.
Our operating income increase was partially offset by:
o Retail margins from our regulated integrated utilities, which reduced
pre-tax earnings by $132 million due to the combined impacts of
weather, a continued weak economy and replacement power costs
associated with our Cook Plant outages.
o Lower demand at our Ohio Companies, which reduced pre-tax earnings by
$11 million. This reduced demand was attributable to mild weather and
economic pressures on industrial customers.
o A reduction in pre-tax earnings of $173 million for the loss of
contributions from our two Texas retail electricity providers that we
sold to Centrica in December 2002. The demand from our two Texas retail
providers was replaced, in part, with a power supply contract with
Centrica that extends through 2004. Our Texas supply margins also
decreased due to an outage at our STP nuclear plant and a separate
provision for potential disallowance by the PUCT of certain historical
fuel expenses. Our Texas supply represents the gross margin for output
of generating units in the ERCOT region and from "reliability must run"
(RMR) contracts with ERCOT.
Investments - Gas Operations
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Net Loss from our Gas Operations, which includes Louisiana Intrastate Gas and
Houston Pipe Line operations, increased $25 million from the comparable quarter
in 2002 due to lower margins resulting from our reduced risk profile and MTM
gains recorded on contracts during the third quarter of 2002, which did not
recur during 2003. The increased loss was partially offset by reduced operating
expenses of $4 million.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- -----------------------------------------------------------------------------
30, 2002
- --------
Net Loss from our Gas Operations of $59 million decreased $16 million from the
comparable period in 2002. We reduced Operating expenses by $22 million and
interest expense by $8 million. These favorable factors are partially offset by
reductions in margins resulting from our reduced risk profile and MTM gains,
which did not recur during 2003.
Investments - UK Operations
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Net Loss from our UK Operations, which includes Fiddler's Ferry and Ferrybridge
plants (FFF), increased by $46 million. During the third quarter, pre-tax gross
margins declined by $54 million driven by timing differences which result in
losses on coal and financial freight contracts that are marked-to-market and
that are not offset during the quarter by mark-to-market gains on physical
freight contracts because physical freight contracts are accounted for on a
settlement basis. Our net loss was also greater due to reduced trading activity
and weaker power trading margins. Operation and maintenance expense increased by
$14 million due to incentives, severance and corporate charges. The operating
loss in the current quarter was partially offset by reduced income taxes.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Net Loss from our UK Operations increased by $94 million due to the reductions
in operating income. During the period, pre-tax gross margins declined due to
timing differences in the accounting treatment for physical freight versus
hedging transactions noted above. Our net loss was also driven by increases in
operations and maintenance costs, which included severance and redundancy costs
of the Nordic trading office.
Investments - Other
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Net Loss from our Other investments, which consists of investments in
independent power plants, coal mines, river transportation, and communications,
was $44 million in the third quarter of 2003, an increase of $25 million over
the comparable quarter in 2002. During the third quarter of 2003, two of our
independent generation facilities became impaired and we recognized a loss of
$45 million. This loss was partially offset by favorable variances caused by the
2002 wind-down of our communications operations, a Vale impairment in 2002, and
2002 pre-tax losses for investments in Dynetec and Altra Energy, which did not
recur in 2003. AEP Pro Serv's (Pro Serv) operating margins decreased by $4
million during 2003 from the comparable quarter in 2002.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Net Loss from our Other investments decreased by $30 million due to lower
international development costs, reduced interest expense and lower costs to
wind-down operations. These decreases were partially offset by our impairment of
two of our independent generation facilities during 2003. Pro Serv's operating
margins decreased by $19 million during 2003 from the comparable period in 2002.
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 certain debt ratings.
The completion of these reviews was a culmination of rating actions started
during 2002.
Liquidity
At September 30, 2003, our liquidity sources totaled $4.6 billion and we had an
available liquidity position of $4.2 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 351* 10/03
Letter of Credit Facility 200 9/06
-------
Total 3,051
Liquidity Reserves 300**
Other Temporary
Investments 1,234**
-------
Total Liquidity Sources 4,585
Less: Commercial Paper
Outstanding 427
Letter of Credit
Outstanding 8
Total Available Liquidity $4,150
=======
* One of the Euro Revolving Credit Facilities has expired and has not been
renewed. The remaining facility was renewed, for a one-year term, in the
amount of 150 million (Euro) during October 2003.
** Liquidity Reserves, Other Temporary Investments and $174 million of
operational cash on hand make up the $1,708 million Cash and Cash
Equivalents balance on our Consolidated Balance Sheet at September 30, 2003.
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 reduced the quarterly common stock
dividend to $0.35 per share, which was a 42% decrease from the previous
dividend of $0.60 per share. This reduction will result in annual cash savings
of approximately $395 million.
Cash Flow
Nine Months Ended
2003 2002
---- ----
(in millions)
Cash and cash equivalents at beginning of period $1,213 $224
------- ------
Net cash from (used for) continuing operations:
Operating activities 1,553 746
Investing activities (885) (19)
Financing activities (173) (397)
Effect of exchange rate changes on cash and
cash equivalents - (3)
------- ------
Net increase in cash and cash equivalents 495 327
------- ------
Cash and cash equivalents at end of period $1,708 $551
======= ======
Cash from operations, a bank-sponsored receivables purchase agreement 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 (through the agreement referenced above) to provide
liquidity for the domestic electric subsidiaries. Short-term borrowings are
supported by three revolving credit agreements.
Operating Activities
Cash flows from operating activities during the first nine months of 2003 were
$1,553 million. Beginning with Income Before Discontinued Operations and
Cumulative Effect of Accounting Changes of $695 million, we add depreciation,
amortization and deferred taxes of $1,334 million and deduct $169 million of
non-cash ECOM, $83 million in mark-to-market changes and $296 million for
working capital changes. The negative working capital changes include $90
million paid to Williams Companies in settlement for power and gas transactions,
and $59 million in increased fuel inventories.
Investing Activities
Cash flows used for investing activities during the first nine months of 2003
were $885 million compared to $19 million during 2002. The major reason for the
year-over-year variance was a construction expenditures reduction of $196
million in 2003 and proceeds of $1,116 million from the sale of assets in 2002.
The 2002 sale of assets was part of our plan to sell non-core investments and
improve our liquidity.
Total consolidated plant and property additions for the first nine months of
2003 were $941 million, including continued construction expenditures for
emission control technology at several coal-fired generating plants (see Note
6).
Financing Activities
Cash flows used for financing activities in the first nine months of 2003
decreased by $224 million compared to 2002, primarily as the result of AEP's
reduction in the common stock dividend. During the first nine months of 2003,
AEP retired $4,789 million of debt ($2,825 million short-term and $1,964 million
of long-term) and increased available cash primarily through the issuance of
long-term financing ($4,146 million), the issuance of common stock ($1,177
million) and the generation of cash from operating activities. Also, see Note 12
for further information on financing activities.
Significant Factors
- -------------------
Possible Divestitures
We are firmly committed to continually evaluate the need to reallocate resources
to areas that effectively match our investments with our business strategy and
provide the greatest potential for financial returns. Similarly, we are
committed to disposing of investments that no longer meet these principles.
We are seeking to divest substantially all of our non-regulated assets including
domestic and international unregulated generation, gas pipelines, a coal
business, independent power producers (IPP) and a communications business. In
June 2003, we began actively seeking buyers for 4,497 megawatts of unregulated
generating capacity in Texas. The value received from this disposition will also
be used to calculate our stranded costs in Texas (see Note 5). We expect to
receive final bids in the fourth quarter of 2003.
During the second quarter of 2003, we also hired an advisor to evaluate our coal
business, which has resulted in receipt of non-binding bids. We are currently
evaluating these bids.
During the third quarter of 2003, management hired advisors to review business
options regarding various investment components of our Gas Operations. We
distributed an initial offering memorandum and request for proposal on the sale
of our Louisiana Intrastate Gas and Jefferson Island Storage Facility operations
in the fourth quarter of 2003.
During the third quarter of 2003, we initiated an effort to sell four domestic
IPP investments. Based on studies using current market assumptions, we believe
that two of the facilities have declines in fair value that are other than
temporary in nature. As a consequence, we recorded an impairment of $70 million
($45.5 million net of tax) in the third quarter of 2003. During the fourth
quarter of 2003, we distributed an information memorandum related to the
possible sale of our interest in these IPPs.
During the fourth quarter of 2003, we selected an advisor for the disposition of
our UK business. We are evaluating the market for possible disposition of these
UK assets prior to our assumed date of year-end 2004.
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 sought regulatory 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. Further, legislation in some of our states
requires RTO participation.
In May 2002, we announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to be
negotiated. In July 2002, FERC issued an order accepting our decision to
participate in PJM, subject to specified conditions. AEP and other parties
continue to work on the resolution of those conditions.
In December 2002, our subsidiaries that operate in the states of Indiana,
Kentucky, Ohio and Virginia filed for state regulatory commission approval of
their plans to transfer functional control of their transmission assets to PJM.
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. In August 2003, AEP
sought and received rehearing of the KPSC's order, allowing us to file
additional evidence in this proceeding. In September 2003, the IURC issued an
order approving I&M's transfer of functional control over its transmission
facilities to PJM, subject to certain specified conditions. Proceedings in the
other states remain pending.
In February 2003, Virginia enacted legislation that prohibited the transfer of
transmission assets in its jurisdiction to an RTO until, at the earliest, July
2004 and only with the approval of Virginia SCC.
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.
If AEP East companies do not obtain regulatory approval to join PJM, we are
committed to reimburse PJM for certain project implementation costs (presently
estimated at $23 million for the entire PJM integration project). AEP also has
$24 million, at September 30, 2003, of deferred RTO formation/integration costs
for which we plan to seek recovery in the future. See Note 4 for further
discussion.
AEP West companies are members of ERCOT or SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and SPP. State
public utility commissions also regulate our SPP companies. The Louisiana and
Arkansas commissions filed responses to the FERC's RTO order indicating that
additional analysis was required. Subsequently, the proposed SPP/MISO
combination was terminated. On October 15, 2003, SPP filed a proposal at FERC
for recognition as an RTO. Regulatory activities concerning various RTO issues
are ongoing in Arkansas and Louisiana.
On September 29 and 30, 2003, the FERC held a public inquiry regarding RTO
formation, including delays in AEP's participation in PJM.
Management is unable to predict the outcome of these regulatory actions and
proceedings or their impact on our transmission operations, results of
operations and cash flows or the timing and operation of RTOs.
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 in various state regulatory
jurisdictions is presented in Note 5.
Restructuring legislation in Texas provides that the PUCT address several issues
in the 2004 true-up proceeding. One of these issues is the wholesale capacity
auction true-up. TCC has recorded $431 million of regulatory assets and related
revenues through September 30, 2003 based upon our estimate.
In July 2003, the PUCT Staff published their proposed filing package for the
2004 true-up proceeding. Within the filing package are instructions and sample
schedules that demonstrate the calculation of the wholesale capacity auction
true-up. That calculation differs from the methodology being employed by TCC.
TCC filed comments on the proposed 2004 true-up filing package in September 2003
and took exception to the methodology employed by the PUCT Staff. A true-up
filing package will probably be approved by the PUCT in the fourth quarter of
2003. If the PUCT Staff's methodology is approved, TCC's wholesale capacity
auction true-up regulatory asset could require adjustment.
In October 2003, a coalition of consumer groups (the Coalition of Ratepayers)
including the Office of Public Utility Counsel, the State of Texas, Cities
served by CPL and Texas Industrial Energy Consumers filed a petition with the
PUCT requesting that the PUCT initiate a rulemaking to amend the PUCT's stranded
cost true-up rule (True-up Rule). The Coalition of Ratepayers proposed to amend
the True-up Rule to revise the calculation of the wholesale capacity auction
true-up. If adopted, the Coalition of Ratepayers' proposal would substantially
reduce or possibly eliminate the wholesale capacity auction true-up regulatory
asset that TCC has accrued in 2002 and 2003. The PUCT requested that responses
to the Coalition of Ratepayers' petition be filed by November 7, 2003. On
November 5, 2003, the PUCT denied the Coalition of Ratepayers' petition.
See Notes 4 and 5 for further discussion.
In the event we are unable, after the 2004 true-up proceeding, to recover all or
a portion of our generation-related regulatory assets, unrecovered fuel
balances, stranded costs, wholesale capacity auction true-up regulatory assets,
other restructuring true-up items and costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.
Nuclear Plant Outages
In April 2003, engineers at STP, during inspections conducted regularly as part
of refueling outages, found wall cracks in two bottom mounted instrument guide
tubes of STP Unit 1. These tubes were repaired and the unit returned to service
in August 2003. Our share of the cost of repair for this outage was
approximately $6 million. We had commitments to provide power to customers
during the outage. Therefore, we were subject to fluctuations in the market
prices of electricity and purchased replacement energy.
In April 2003, both units of Cook Plant were taken offline due to an influx of
fish in the plant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of damage caused by the fish
intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to
service in June following completion of a scheduled refueling outage.
Litigation
Federal EPA Complaint and Notice of Violation
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), AEPSC, APCo, CSPCo, I&M, and OPCo are involved in
litigation regarding generating plant emissions under the Clean Air Act. The
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. The 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 that 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 6 for further discussion.
NOx Reductions
The 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 other
combustion control 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 approximately $1 billion has been spent through
September 30, 2003. The actual cost to comply could be significantly different
than these 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, these
costs would adversely affect future results of operations, cash flows and
possibly financial condition. See Note 6 for further discussion.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of 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. We also have various HPL related
contingencies and indemnities from Enron including issues related to the
underground Bammel gas storage facility and the cushion gas (pad gas) required
for its normal operation.
In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related collateral
across various Enron entities and seeking payment of approximately $125 million
plus interest. We will assert our right to offset trading payables owed to
various Enron entities against trading receivables due to several AEP
subsidiaries. Management is unable to predict the ultimate resolution of these
issues or their impact on results of operations, cash flows and financial
condition. See Note 6 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 the appropriate trading
contract and industry practice in calculating termination and liquidation
amounts and that BOM had acknowledged just prior to the termination and
liquidation that it owed us approximately $68 million. We are claiming that BOM
owes us 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 settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter had an immaterial
impact on results of operations and financial condition. See Note 6 for further
discussion.
Arbitration of PG&E Energy Trading, LLC Claim
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11
million to PGET. The settlement amount approximated the amount payable that, in
the ordinary course of business, we recorded as part of our trading activity
using MTM accounting. As a result, the settlement payment did not have a
material impact on results of operations, cash flows or financial condition.
Energy Market Investigations
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 (CFTC), the U.S. Department
of Justice and the California attorney general during 2002. Management responded
to the inquiries and provided the requested information and has continued to
respond to supplemental data requests in 2003.
In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC seeking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. The case is in the initial pleading stage. Although
management is unable to predict the outcome of this case, it is not expected to
have a material effect on results of operations or cash flows.
Management cannot predict what, if any further action, any of these governmental
agencies may take with respect to these matters.
Shareholders' Litigation
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against us, certain
executives, members of the Board of Directors and certain investment banking
firms. We intend to vigorously defend against these actions. See Note 6 for
further discussion.
California Lawsuit
In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP has been dismissed
from the case. See Note 6 for further discussion.
Cornerstone Lawsuit
In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Shortly thereafter, a similar action was filed in the same court against
eighteen companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. These cases
are in the initial pleading stage. Management believes that the cases are
without merit and intends to vigorously defend against them.
Texas Commercial Energy, LLP Lawsuit
Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against us and
four AEP subsidiaries, certain unaffiliated energy companies and ERCOT alleging
violations of the Sherman Antitrust Act, fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, civil conspiracy and negligence.
The allegations, not all of which are made against the AEP companies, range from
anticompetitive bidding to withholding power. TCE alleges that these activities
resulted in price spikes requiring TCE to post additional collateral and
ultimately forced it into bankruptcy when it was unable to raise prices to its
customers due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary damages and
court costs. Management believes that the claims against us are without merit.
We intend to vigorously defend against the claims. See Note 6 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. The settlement amount was
less than the amount receivable that, in the ordinary course of business, we
recorded as part of our trading activity using MTM accounting. As a result, we
incurred 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 3 for a discussion of 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 (Liabilities)
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 (Liabilities)
Nine Months Ended September 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) (118) 122 16 20
Fair Value of New Contracts When Entered
Into During the Period (b) - - - -
Net Option Premiums Paid/(Received) (c) 1 32 (12) 21
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) 42 39 (45) 36
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e)
4 - - 4
----- ------ ----- -----
Ending Balance September 30, 2003 $270 $40 $(10) $300
===== ====== ===== =====
(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 (Liabilities)
As of September 30, 2003
Utility Gas UK
Operations Operations Operations Consolidated
---------- ---------- ---------- ------------
(in millions)
Current Assets $300 $297 $362 $959
Non Current Assets 376 186 247 809
------ ------ ------ --------
Total MTM Risk Management Contract Assets $676 $ 483 $609 $ 1,768
------ ------ ------ --------
Current Liabilities $(198) $(214) $(420) $ (832)
Non Current Liabilities (208) (229) (199) (636)
------ ------ ------ --------
Total MTM Risk Management Contract Liabilities $(406) $(443) $(619) $(1,468)
------ ------ ------ --------
Total MTM Risk Management Contract Net Assets
(Liabilities) $ 270 $40 $(10) 300
====== ====== ====== ========
Net Non-Trading Related Derivative Contracts (288)
--------
Risk Management and Derivative Contract Net Assets $12
========
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
(Liabilities)
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information.
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 (Liabilities)
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---- ---- ---- ---- ---- ---- -----
(in millions)
Utility Operations:
Prices Actively Quoted - Exchange Traded
Contracts $(5) $(15) $(3) $(1) $- $- $(24)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) (1) 101 27 22 5 - 154
Prices Based on Models and Other
Valuation Methods (b) 28 23 (6) 21 24 50 140
----- ----- ---- ---- ---- ---- -----
Total $22 $109 $18 $42 $29 $50 $270
===== ===== ==== ==== ==== ==== =====
Gas Operations:
Prices Actively Quoted - Exchange
Traded Contracts $(64) $96 $8 $- $ - $ - $40
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 27 (12) 1 - - - 16
Prices Based on Models and Other
Valuation Methods (b) (15) 15 (3) (6) 1 (8) (16)
----- ----- ---- ---- ---- ---- -----
Total $(52) $99 $6 $(6) $1 $(8) $40
===== ===== ==== ==== ==== ==== =====
UK Operations:
Prices Actively Quoted - Exchange Traded
Contracts $- $- $ - $- $- $- $-
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 43 (50) 15 (7) (2) - (1)
Prices Based on Models and Other
Valuation Methods (b) (7) - (1) (1) - (9)
----- ----- ---- ---- ---- ---- -----
Total $36 $(50) $15 $(8) $(3) $- $(10)
===== ===== ==== ==== ==== ==== =====
Consolidated:
Prices Actively Quoted - Exchange Traded
Contracts $(69) $81 $5 $(1) $- $- $16
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 69 39 43 15 3 - 169
Prices Based on Models and Other
Valuation Methods (b) 6 38 (9) 14 24 42 115
----- ----- ---- ---- ---- ---- -----
Total $6 $158 $39 $28 $27 $42 $300
===== ===== ==== ==== ==== ==== =====
(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 September 30, 2003
Tenor
Domestic (in months)
-------- -----------
Natural Gas Forward Purchases and Sales
NYMEX Henry Hub Gas 72
Gas East - Northeast, Mid-continent
Gulf Coast, Texas 25
Gas West - Permian Basin, San Juan,
Rocky Mtns, Kern, Cdn
Border (Sumas),
Malin, PGE Citygate, AECO 25
Over the Counter Options 13
Power (Peak) Forward Purchases and Sales
Power East - Cinergy 27
Power East - PJM 39
Power East - NYPP 27
Power East - NEPOOL 27
Power East - ERCOT 15
Power East - TVA 0
Power East - Com Ed 7
Power East - Entergy 15
Power West - PV, NP15, SP15, MidC, Mead
51
Peak Power Volatility
(Options) Cinergy 15
OffPeak Power Volatility All Regions 0
Natural Gas
Liquids 14
WTI Crude 48
Emissions 27
Coal 27
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 is exposed to market fluctuations in energy commodity prices impacting its
power operations. AEP monitors these risks on its future operations and may
employ various commodity instruments as cash flow hedges to mitigate the impact
of these fluctuations on the future cash flows from its assets. AEP dos not
hedge all commodity price risk.
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 (Loss)
On the Balance Sheet as of September 30, 2003
Portion Expected to
Accumulated Other Be Reclassified to
Comprehensive Income Earnings During the
(Loss) After Tax (a) Next 12 Months (b)
--------------------- -------------------
(in millions)
Power $(172) $(83)
Foreign Currency (10) (8)
Interest Rate (11) (5)
------ -----
AEP Consolidated $(193) $(96)
====== =====
Total Other Comprehensive Income Activity
Nine Months Ended September 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) (171) (9) 3 (177)
Reclassifications from OCI to Net
Income (d) 2 - (2) -
------ ----- ----- ------
Accumulated OCI Derivative Loss September
30, 2003 $(172) $(10) $(11) $(193)
====== ===== ===== ======
(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 items affecting net income. Amounts are reported net of related
income taxes.
(d) Reclassifications from AOCI to net income - Gains or losses from
derivatives used as hedging instruments in cash flow hedges that were
reclassified into net income during the reporting period. Amounts are
reported net of related income taxes above.
Credit Risk
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 September 30, 2003. At September 30, 2003, AEP's credit exposure
net of credit collateral to sub investment grade counterparties was
approximately 11%, expressed in terms of net MTM assets and net receivables. As
of September 30, 2003, the following table approximates counterparty credit
quality and exposure for AEP based on netting across AEP 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 $1,002 $ 32 $ 970 2 $243
Split Rating 27 - 27 1 27
Non-Investment Grade 169 96 73 3 29
No External Ratings:
Internal Investment
Grade 292 7 285 1 90
Internal Non-Investment
Grade 128 50 78 1 10
------- ----- ------- - -----
Total $1,618 $185 $1,433 8 $399
======= ===== ======= = =====
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 September 30, 2003
2003 2004 2005
---- ---- ----
Estimated Plant Output Hedged (a) 94% 92% 84%
(a) Estimated Plant Output Hedged - Represents the portion of
megawatt-hours of future generation/production for which AEP has
sales commitments or estimated requirements obligations 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 and a one-day
holding period. Based on this VaR analysis, at September 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
September 30, 2003 December 31, 2002
------------------ -----------------
(in millions) (in millions)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$7 $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.
CCRO VaR Metrics
Average for
End of Year-to-Date High for Low for
September 30, 2003 2003 Year-to-Date 2003 Year-to-Date 2003
------------------- ------------ ------------------ -----------------
(in millions)
95% Confidence Level, Ten-Day
Holding Period $28 $26 $71 $17
99% Confidence Level, One-Day
Holding Period $12 $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 and a one-year holding period. The volatilities and
correlations were based on three years of daily prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $1,156 million at
September 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 our 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
For the Three and Nine Months Ended September 30, 2003 and 2002
(in millions, except per-share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
2003 2002 2003 2002
---- ---- ---- ----
REVENUES
- ----------------------------------------------------------------------
Utility Operations $3,111 $2,940 $8,512 $7,858
Gas Operations 860 700 2,791 1,803
U.K. Operations and Other 138 171 555 723
------- ------- ------- -------
TOTAL 4,109 3,811 11,858 10,384
------- ------- ------- -------
EXPENSES
- ----------------------------------------------------------------------
Fuel for Electric Generation 916 666 2,426 1,918
Purchased Electricity for Resale 206 306 626 413
Purchased Gas for Resale 828 625 2,685 1,691
Maintenance and Other Operation 977 868 2,921 3,073
Depreciation and Amortization 334 362 985 1,045
Taxes Other Than Income Taxes 179 202 524 576
------- ------- ------- -------
TOTAL 3,440 3,029 10,167 8,716
------- ------- ------- -------
OPERATING INCOME 669 782 1,691 1,668
------- ------- ------- -------
Other Income 75 115 279 176
------- ------- ------- -------
INTEREST AND OTHER CHARGES
- ----------------------------------------------------------------------
Investment Value and Other Impairment Losses 70 - 70 -
Other Expense 51 75 153 101
Interest 217 181 620 572
Preferred Stock Dividend Requirements of Subsidiaries 1 3 7 8
Minority Interest in Finance Subsidiary - 9 17 27
------- ------- ------- -------
TOTAL 339 268 867 708
------- ------- ------- -------
INCOME BEFORE INCOME TAXES 405 629 1,103 1,136
Income Taxes 148 243 408 433
------- ------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT 257 386 695 703
Discontinued Operations (net of tax) - 39 (16) (35)
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 $257 $425 $872 $318
======= ======= ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 395 339 382 329
======= ======= ======= =======
EARNINGS (LOSS) PER SHARE
- ----------------------------------------------------------------------
Income Before Discontinued Operations And Cumulative Effect
of Accounting Changes $0.65 $1.14 $1.81 $2.14
Discontinued Operations - 0.11 (0.04) (0.10)
Cumulative Effect of Accounting Changes - - 0.51 (1.07)
------- ------- ------- -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE) $0.65 $1.25 $2.28 $0.97
======= ======= ======= =======
CASH DIVIDENDS PAID PER SHARE $0.35 $0.60 $1.30 $1.80
======= ======= ======= =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in millions)
CURRENT ASSETS
- ----------------------------------------------------------------------------------
Cash and Cash Equivalents $1,708 $1,213
Accounts Receivable (net) 1,535 1,740
Fuel, Materials and Supplies 1,197 1,166
Risk Management Assets 1,014 1,012
Other 901 935
-------- --------
TOTAL 6,355 6,066
-------- --------
PROPERTY, PLANT AND EQUIPMENT
- ----------------------------------------------------------------------------------
Electric:
Production 18,616 17,031
Transmission 6,099 5,882
Distribution 9,815 9,573
Other (including gas, coal mining and nuclear fuel) 3,997 3,965
Construction Work in Progress 973 1,406
-------- --------
TOTAL 39,500 37,857
Less: Accumulated Depreciation and Amortization 16,488 16,173
-------- --------
TOTAL-NET 23,012 21,684
-------- --------
OTHER NON-CURRENT ASSETS
- ----------------------------------------------------------------------------------
Regulatory Assets 2,612 2,688
Securitized Transition Assets 703 735
Investments in Power and Distribution Projects 221 283
Goodwill 397 396
Assets Held for Sale 194 277
Assets of Discontinued Operations - 15
Long-term Risk Management Assets 818 819
Other 1,767 1,783
-------- --------
TOTAL 6,712 6,996
-------- --------
TOTAL ASSETS $36,079 $34,746
======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2003 and December 31, 2002
(Unaudited)