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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)
2003 2002
---- ----
(in millions)
CURRENT LIABILITIES
- ---------------------------------------------------------------------------------------
Accounts Payable $1,700 $2,030
Short-term Debt 443 3,164
Long-term Debt Due Within One Year 1,234 1,633
Risk Management Liabilities 1,029 1,113
Other 1,782 1,802
-------- --------
TOTAL 6,188 9,742
-------- --------
NON-CURRENT LIABILITIES
- ---------------------------------------------------------------------------------------
Long-term Debt 12,323 8,487
Equity Unit Senior Notes 376 376
Long-term Risk Management Liabilities 791 481
Deferred Income Taxes 4,144 3,916
Deferred Investment Tax Credits 431 455
Deferred Credits and Regulatory Liabilities 837 770
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 178 185
Liabilities Held for Sale 98 130
Liabilities of Discontinued Operations - 12
Other 2,111 1,903
Commitments and Contingencies (Note 6)
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption 83 -
-------- --------
TOTAL 21,372 16,715
-------- --------
TOTAL LIABILITIES 27,560 26,457
-------- --------
Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption 61 -
Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries - 321
Minority Interest in Finance Subsidiary - 759
Cumulative Preferred Stocks of Subsidiaries - 145
COMMON SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------------
Common Stock-Par Value $6.50:
2003 2002
---- ----
Shares Authorized. . . . . . . . . . .600,000,000 600,000,000
Shares Issued. . . . . . . . . . . . .404,004,712 347,835,212
(8,999,992 shares were held in treasury at September 30, 2003 and December 31, 2002) 2,626 2,261
Paid-in Capital 4,184 3,413
Accumulated Other Comprehensive Income (Loss) (745) (609)
Retained Earnings 2,393 1,999
-------- --------
TOTAL 8,458 7,064
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $36,079 $34,746
======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in millions)
OPERATING ACTIVITIES
- -------------------------------------------------------------------------------------
Net Income $872 $318
Plus: Discontinued Operations 16 35
------- -------
Income from Continuing Operations 888 353
Adjustments for Noncash Items:
Depreciation and Amortization 984 1,066
Deferred Income Taxes 256 (81)
Deferred Investment Tax Credits (24) (21)
Cumulative Effect of Accounting Changes (193) 350
Impairments 46 -
Amortization of Deferred Property Taxes 88 73
Amortization of Cook Plant Restart Costs 30 30
Mark to Market of Risk Management Contracts (83) 217
Changes in Certain Current Assets and Liabilities:
Accounts Receivable, net 176 (868)
Fuel, Materials and Supplies (59) (176)
Accrued Utility Revenues 70 (255)
Prepayments and Other (37) (387)
Accounts Payable (400) 771
Taxes Accrued (34) 126
Interest Accrued 30 107
Over/Under Fuel Recovery 131 (57)
Change in Other Assets (224) (373)
Change in Other Liabilities (92) (129)
------- -------
Net Cash Flows From Operating Activities 1,553 746
------- -------
INVESTING ACTIVITIES
- -------------------------------------------------------------------------------------
Construction Expenditures (941) (1,137)
Proceeds from Sale of Assets 49 1,116
Other 7 2
------- -------
Net Cash Flows Used For Investing Activities (885) (19)
------- -------
FINANCING ACTIVITIES
- -------------------------------------------------------------------------------------
Issuance of Common Stock 1,177 656
Issuance of Long-term Debt 4,146 1,819
Issuance of Equity Unit Senior Notes - 334
Change in Short-term Debt, net (2,825) (806)
Retirement of Long-term Debt (1,964) (1,800)
Retirement of Preferred Stock (2) (10)
Retirement of Minority Interest (225) -
Dividends Paid on Common Stock (480) (590)
------- -------
Net Cash Flows Used For Financing Activities (173) (397)
------- -------
Effect of Exchange Rate Change on Cash - (3)
------- -------
Net Increase in Cash and Cash Equivalents 495 327
Cash and Cash Equivalents at Beginning of Period 1,213 224
------- -------
Cash and Cash Equivalents at End of Period $1,708 $551
======= =======
Net Decrease in Cash and Cash Equivalents from Discontinued Operations $(1) $(25)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 8 108
------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $7 $83
======= =======
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $542 million and $555
million and for income taxes was $156 million and $242 million in 2003 and 2002,
respectively. Noncash acquisitions under capital leases were $9 million in 2003
and $1 million in 2002.
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
COMPREHENSIVE INCOME (LOSS)
(in millions)
(Unaudited)
Accumulated
Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
JANUARY 1, 2002 $2,153 $2,906 $3,296 $(126) $8,229
Issuance of Common Stock 108 568 676
Common Stock Dividends (590) (590)
Other (80) 15 (65)
-------
TOTAL 8,250
-------
COMPREHENSIVE INCOME (LOSS)
- -----------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 97 97
Unrealized Gains on Cash Flow Hedges 4 4
Unrealized Losses on Securities Available for Sale (3) (3)
NET INCOME 318 318
-------
TOTAL COMPREHENSIVE INCOME 416
------- ------- ------- ------ -------
SEPTEMBER 30, 2002 $2,261 $3,394 $3,039 $ (28) $8,666
======= ======= ======= ====== =======
JANUARY 1, 2003 $2,261 $3,413 $1,999 $(609) $7,064
Issuance of Common Stock 365 812 1,177
Common Stock Dividends (480) (480)
Common Stock Expense (36) (36)
Other (5) 2 (3)
-------
TOTAL 7,722
-------
COMPREHENSIVE INCOME (LOSS)
- -----------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 25 25
Unrealized Losses on Cash Flow Hedges (177) (177)
Unrealized Gains on Securities Available for Sale 1 1
Minimum Pension Liability 15 15
NET INCOME 872 872
-------
TOTAL COMPREHENSIVE INCOME 736
------- ------- ------- ------ -------
SEPTEMBER 30, 2003 $2,626 $4,184 $2,393 $(745) $8,458
======= ======= ======= ====== =======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in millions)
TOTAL LONG-TERM DEBT OUTSTANDING
First Mortgage Bonds $1,247 $1,884
Installment Purchase Contracts 1,937 1,680
Notes Payable 323 520
Senior Unsecured Notes 8,171 4,819
Junior Debentures - 205
Securitization Bonds 746 797
Notes Payable to Caddis 527 -
Notes Payable to Trust 321 -
Other Long-term Debt 358 247
Unamortized Discount (net) (73) (32)
-------- -------
TOTAL 13,557 10,120
Less Portion Due Within One Year 1,234 1,633
-------- -------
TOTAL LONG-TERM PORTION $12,323 $8,487
======== =======
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. GENERAL
-------
The accompanying unaudited interim financial statements should be read
in conjunction with the 2002 Annual Report (as updated by the Current
Report on Form 8-K dated May 14, 2003) as incorporated in and filed with
the Form 10-K/A.
Certain prior period financial statement items have been reclassified to
conform to current period presentation. These items include the effects
of discontinued operations, gains and losses associated with derivative
trading contracts presented on a net basis in accordance with EITF 02-3,
and counterparty netting in accordance with FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts" and EITF Topic
D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy
under FASB Interpretation No. 39." Such reclassifications had no effect
on previously reported Net Income. In addition, management determined
that certain amounts were misclassified in AEP's 2002 Consolidated
Statement of Operations resulting from errors in the coding of certain
intercompany transactions and from transactions associated with our UK
operations (see Note 30 in the Current Report on Form 8-K dated May 14,
2003). As a result, Gas Operations revenues increased by $41 million and
decreased by $8 million and UK Operations and Other revenues increased
by $2 million and decreased by $11 million for the three and nine month
periods ended September 30, 2002, respectively. Fuel for Electric
Generation decreased by $16 million and $60 million and Purchased Gas
for Resale decreased by $51 million and $213 million for the three and
nine month periods ended September 30, 2002, respectively. Expenses for
Maintenance and Other Operation increased by $105 million and $235
million and Taxes Other Than Income Taxes increased by $5 million and
$19 million for the three and nine month periods ended September 30,
2002, respectively. These revisions had no effect on Operating Income or
Net Loss.
In the opinion of management, the unaudited interim financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
2. SIGNIFICANT ACCOUNTING POLICIES
-------------------------------
Accumulated Other Comprehensive Income
We expect to reclassify approximately $96 million of net losses from
cash flow hedges in Accumulated Other Comprehensive Income (Loss) at
September 30, 2003 to net income during the next twelve months at the
time the hedged transactions affect net income. Seven years approximates
the maximum period over which an exposure to a variability in future
cash flows is hedged; less than 2% have a term longer than seven years.
The actual amounts that we reclassify from Accumulated Other Comprehensive
Income to Net Income can differ due to market price changes.
3. NEW ACCOUNTING PRONOUNCEMENTS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES
-------------------------------------------------------------------------
FIN 46 "Consolidation of Variable Interest Entities"
We implemented FIN 46, "Consolidation of Variable Interest Entities,"
effective July 1, 2003. FIN 46 interprets the application of Accounting
Research Bulletin No. 51, "Consolidated Financial Statements," to
certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support from other parties.
Due to the prospective application of FIN 46, we did not reclassify
prior period amounts.
On July 1, 2003, we deconsolidated Caddis Partners, LLC (Caddis), which
included amounts previously reported as Minority Interest in Finance
Subsidiary ($759 million at December 31, 2002 and $533 million at June
30, 2003). As a result, a note payable to Caddis is reported as a
component of Long-Term Debt ($527 million at September 30, 2003). See
Note 11 "Minority Interest in Finance Subsidiary" for further
disclosures.
On July 1, 2003, we also deconsolidated the trusts which hold
mandatorily redeemable trust preferred securities. Therefore, $321
million, previously reported as Certain Subsidiary Obligated,
Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts
Holding Solely Junior Subordinated Debentures of Such Subsidiaries, is
now reported as Notes Payable to Trust and is included in Long-term
Debt.
Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company
(Sabine), a contract mining operation providing mining services to
SWEPCo. Upon consolidation, SWEPCo recorded the assets and liabilities
of Sabine ($77.8 million). Also, after consolidation, SWEPCo currently
records all expenses (depreciation, interest and other operation
expense) of Sabine and eliminates Sabine's revenues against SWEPCo's
fuel expenses. There is no cumulative effect of an accounting change
recorded as a result of our requirement to consolidate, and there is no
change in net income due to the consolidation of Sabine.
Effective July 1, 2003, OPCo consolidated JMG Funding, LP (JMG). Upon
consolidation, OPCo recorded the assets and liabilities of JMG ($469.6
million). OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's
operating lease expenses. There is no cumulative effect of an accounting
change recorded as a result of our requirement to consolidate JMG, and
there is no change in net income due to the consolidation of JMG. See
Note 10 "Leases" for further disclosures.
SFAS 143 "Accounting for Asset Retirement Obligations"
We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability
at fair value for any legal obligations for asset retirements in the
period incurred. Upon establishment of a legal liability, SFAS 143
requires a corresponding asset to be established which will be
depreciated over its useful life. SFAS 143 requires that a cumulative
effect of change in accounting principle be recognized for the
cumulative accretion and accumulated depreciation that would have been
recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in
accounting principle is favorably affected by the reversal of
accumulated removal cost. These costs had previously been recorded for
generation and did not qualify as a legal obligation although these
costs were collected in depreciation rates by certain formerly regulated
subsidiaries.
We completed a review of our asset retirement obligations and concluded
that we have related legal liabilities for nuclear decommissioning costs
for our Cook Plant and our partial ownership in the South Texas Project,
as well as liabilities for the retirement of certain ash ponds, wind
farms, the U.K. Plants, and certain coal mining facilities. Since we
presently recover our nuclear decommissioning costs in our regulated
cash flow and have existing balances recorded for such nuclear
retirement obligations, we recognized the cumulative difference between
the amount already provided through rates and the amount as measured by
applying SFAS 143 as a regulatory asset or liability. Similarly, a
regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In
the first quarter of 2003, we recorded an unfavorable cumulative effect
of $45.4 million after tax for our non-regulated operations ($38.0
million related to Ash Ponds in the Utility Operations segment, $7.2
million related to U.K. Plants in the Investments - UK Operations
segment and $0.2 million for Wind Mills in the Investments - Other
segment).
Certain of our operating companies have recorded, in Accumulated
Depreciation and Amortization, removal costs collected from ratepayers
for certain assets that do not have associated legal asset retirement
obligations. To the extent that operating companies have now been
deregulated we reversed the balance of such removal costs, totaling
$287.2 million after tax, from accumulated depreciation which resulted
in a net favorable cumulative effect in the first quarter of 2003.
However, we did not adjust the balance of such removal costs for our
regulated operations, and in accordance with the present method of
recovery, will continue to record such amounts through depreciation
expense and accumulated depreciation. We estimate that we have
approximately $1.2 billion of such regulatory liabilities recorded in
Accumulated Depreciation and Amortization as of both September 30, 2003
and December 31, 2002.
The net favorable cumulative effect of the change in accounting
principle for the nine months ended September 30, 2003 consists of the
following:
Pre-tax After-tax
Income (Loss) Income (Loss)
------------- -------------
(in millions)
Ash Ponds $(62.8) $(38.0)
U.K. Plants, Wind Mills and
Coal Operations (11.3) (7.4)
Reversal of Cost of Removal 472.6 287.2
-------- -------
Total $398.5 $241.8
======== =======
We have identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution and gas
pipeline assets, as a result of certain easements on property on which
we have assets. Generally, such easements are perpetual and require only
the retirement and removal of our assets upon the cessation of the
property's use. The retirement obligation is not estimable for such
easements since we plan to use our facilities indefinitely. The
retirement obligation would only be recognized if and when we abandon or
cease the use of specific easements.
The following is a reconciliation of the beginning and ending aggregate
carrying amount of asset retirement obligations (in millions):
U.K.
Plants,
Wind
Mills
Nuclear Ash and Coal
Decommissioning Ponds Operations Total
--------------- ----- ---------- -----
Asset Retirement Obligation
Liability at
January 1, 2003 $718.3 $69.8 $37.2 $825.3
Accretion expense 39.1 4.2 1.6 44.9
Liabilities incurred - - 8.3 8.3
Foreign currency
translation - - 3.5 3.5
------- ------ ------ -------
Asset Retirement Obligation
Liability at
September 30, 2003 $757.4 $74.0 $50.6 $882.0
======= ====== ====== =======
Accretion expense is included in Maintenance and Other Operation expense
in our accompanying Consolidated Statements of Operations.
As of September 30, 2003 and December 31, 2002, the fair value of assets
that are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $800 million and $716 million,
respectively, recorded in Other Assets on our Consolidated Balance
Sheets.
Pro forma net income and earnings per share are not presented for the
quarter ended September 30, 2002 or the years ended December 31, 2002,
2001 and 2000 because the pro forma application of SFAS 143 would result
in pro forma net income and earnings per share not materially different
from the actual amounts reported during those periods.
Rescission of EITF 98-10
In October 2002, the Emerging Issues Task Force of the FASB reached a
final consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and
related interpretive guidance. Under EITF 02-3, mark-to-market
accounting is precluded for energy trading contracts that are not
derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10
also eliminated the recognition of physical inventories at fair value
other than as provided by GAAP. We have implemented this standard for
all physical inventory and non-derivative energy trading transactions
occurring on or after October 25, 2002. For physical inventory and
non-derivative energy trading transactions entered into prior to October
25, 2002, we implemented this standard on January 1, 2003 and reported
the effects of implementation as a cumulative effect of an accounting
change. We recorded a $49 million after tax loss in net income as
Accounting for Risk Management Contracts in our Consolidated Statements
of Operations in Cumulative Effect of Accounting Changes ($12 million in
Utility Operations, $22 million in Investments - Gas Operations and $15
million in Investments - UK Operations segments).
SFAS 149 "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
On April 30, 2003, the FASB issued Statement No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS
149). SFAS 149 amends SFAS 133 to clarify the definition of a derivative
and the requirements for contracts to qualify as "normal purchase/normal
sale." SFAS 149 also amends certain other existing pronouncements.
Effective July 1, 2003, we implemented SFAS 149 and the effect was not
material to our results of operations, cash flows or financial
condition.
SFAS 150 "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the result
of the first phase of the FASB's project to eliminate from the balance
sheet the "mezzanine" presentation of items with characteristics of both
liabilities and equity.
SFAS 150 requires that the following three types of freestanding
financial instruments be reported as liabilities: (1) mandatorily
redeemable shares, (2) instruments other than shares that could require
the issuer to buy back some of its shares in exchange for cash or other
assets and (3) obligations that can be settled with shares, the monetary
value of which is either (a) fixed, (b) tied to the value of a variable
other than the issuer's shares, or (c) varies inversely with the value
of the issuer's shares. Measurement of these liabilities generally is to
be at fair value, with the payment or accrual of "dividends" and other
amounts to holders reported as interest cost. Upon adoption of SFAS 150,
any measurement change for these liabilities is to be reported as the
cumulative effect of a change in accounting principle.
Beginning with our third quarter 2003 financial statements, $83 million
of mandatorily redeemable Cumulative Preferred Stocks of Subsidiaries is
now presented as Cumulative Preferred Stocks of Subsidiaries Subject to
Mandatory Redemption, a component of Non-Current Liabilities on the
consolidated balance sheets. Beginning July 1, 2003, dividends on these
mandatorily redeemable preferred shares are now classified as interest
expense on the consolidated statements of operations. In accordance with
SFAS 150, dividends from prior periods remain classified as preferred
stock dividends (a component of Preferred Stock Dividend Requirements of
Subsidiaries).
SFAS 142 "Goodwill and Other Intangible Assets"
SFAS 142 requires that goodwill and intangible assets with indefinite
useful lives no longer be amortized, and that goodwill and intangible
assets be tested annually for impairment. The implementation of SFAS 142
resulted in a $350 million after tax net transitional loss in 2002 for
the U.K. and Australian operations and is reported in our Consolidated
Statements of Operations as a cumulative effect of accounting change.
FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
In November 2002, the FASB issued FIN 45 which clarifies the accounting
to recognize a liability related to issuing a guarantee, as well as
additional disclosures of guarantees. This guidance is an interpretation
of SFAS 5, 57 and 107 and a rescission of FIN 34. The initial
recognition and initial measurement provisions of FIN 45 are effective
on a prospective basis for guarantees issued or modified after December
31, 2002. The disclosure requirements of FIN 45 are effective for
financial statements of interim or annual periods ending after December
15, 2002. See Note 7 for further disclosures.
Future Accounting Changes
FASB's standard-setting process is ongoing. Until new standards have
been finalized and issued by FASB, we cannot determine the impact on the
reporting of our operations that may result from any such future
changes.
4. RATE MATTERS
------------
Fuel in SPP Area of Texas
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT
delayed the start of customer choice in the SPP area of Texas. In May
2003, the PUCT ordered that competition would not begin in the SPP areas
before January 1, 2007. The PUCT has ruled that TNC fuel factors in the
SPP area will be based upon the price-to-beat fuel factors offered by
the REP in the ERCOT portion of TNC's service territory. TNC filed with
the PUCT in 2002 to determine the most appropriate method to reconcile
fuel costs in TNC's SPP area. In April 2003, the PUCT issued an order
adopting the methodology proposed in TNC's filing, with adjustments, for
reconciling fuel costs in its SPP area. The adjustments removed $3.71
per MWH from reconcilable fuel expense. This adjustment will reduce
revenues received from TNC's SPP customers by approximately $400,000
annually. These customers are now served by SWEPCo's REP.
TNC Fuel Reconciliation
In June 2002, TNC filed with the PUCT to reconcile fuel costs and to
defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 2000 through December 2001 will be
the final fuel reconciliation for TNC's ERCOT service territory. At
December 31, 2001, the under-recovery balance associated with TNC's
ERCOT service area was $27.5 million including interest. During the
reconciliation period, TNC incurred $293.7 million of eligible fuel
costs serving both ERCOT and SPP retail customers. TNC also requested
authority to surcharge its SPP customers for under-recovered fuel costs.
TNC's SPP customers will continue to be subject to fuel reconciliations
until competition begins in the SPP area. The under-recovery balance at
December 31, 2001 for TNC's service within SPP was $0.7 million
including interest. As noted above, TNC's SPP customers are now being
served by SWEPCo's REP.
In March 2003, the Administrative Law Judges (ALJ) in this proceeding
filed their Proposal for Decision (PFD). The PFD includes a
recommendation that TNC's under-recovered retail fuel balance be reduced
by approximately $12.5 million. In March 2003, TNC established a reserve
of $13 million, including interest, based on the recommendations in the
PFD. On April 22, 2003, TNC and intervenors in this proceeding filed
exceptions to the PFD. On May 28, 2003, the PUCT remanded TNC's final
fuel reconciliation to the ALJ to consider two issues. These remand
issues could result in additional disallowances. The issues are the
sharing of off-system sales margins from AEP's trading activities with
customers through the fuel factor for five years per the PUCT's
interpretation of the Texas AEP/CSW merger settlement and the inclusion
of January 2002 fuel factor revenues and associated costs in the
determination of the under-recovery. The PUCT is proposing that the
sharing of off-system sales margins should continue beyond the
termination of the fuel factor. This would result in the sharing of
margins for an additional three and one half years after the end of the
Texas ERCOT fuel factor. TNC made a filing on July 15, 2003 addressing
the remand issues. Intervenors and the PUCT Staff filed statements of
position or testimony in August 2003 and TNC filed rebuttal testimony in
September 2003. The intervenors recommended $14.3 million of
disallowances for the two remanded issues. On September 9, 2003,
portions of TNC's testimony which related to the requirements of the
AEP/CSW merger settlement to share off-system sales margins were
stricken by the ALJ. The ALJ ruled that the requirement to share
off-system sales margins had been determined by the PUCT and that the
scope of the remand was only to determine the off-system sales margin
sharing methodology. Management believes that the Texas merger
settlement only provided for sharing of margins during the period fuel
and generation costs were regulated by the PUCT and that after a
thorough review of the evidence it is only reasonably possible that TNC
will ultimately share margins after the end of the Texas fuel factor.
Due to a provision established in the first quarter of 2003, the
resolution of the fuel factor issue should have an immaterial impact on
future results of operations, cash flows and financial condition.
However, the ultimate decision could result in additional income
reductions for these issues. It is presently expected that the ALJ's PFD
and the PUCT's final decision regarding these remanded issues will occur
in late 2003 or early 2004.
In February 2002, TNC received a final order from the PUCT in a fuel
reconciliation covering the period July 1997 to June 2000 and reflected
the order in its financial statements. This final order was appealed to
the Travis County District Court. In May 2003, the District Court upheld
the PUCT's final order. That order is currently on appeal to the Third
Court of Appeals.
TCC Fuel Reconciliation
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
defer its over-recovery of fuel for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 1998 through
December 2001 will be TCC's final fuel reconciliation. At December 31,
2001, the over-recovery balance for TCC was $63.5 million including
interest. During the reconciliation period, TCC incurred $1.6 billion of
eligible fuel and fuel-related expenses. Recommendations from
intervening parties were received in April 2003 and hearings were held
in May 2003. Intervening parties have recommended disallowances totaling
$170 million. An ALJ report is expected in 2003 or the first quarter of
2004.
In March 2003, the ALJ hearing the TNC final fuel reconciliation,
discussed above, issued a PFD in the TNC proceeding. Various issues
addressed in TNC's proceeding may also be applicable to TCC's
proceeding. Consequently, TCC established a reserve for potential
adverse rulings of $27 million during the first quarter of 2003. Based
upon the PUCT's remand of certain TNC issues, TCC established an
additional reserve of $9 million in the second quarter of 2003. In July
2003, the ALJ requested that additional information be provided in the
TCC fuel reconciliation related to the impact of the TNC remand order on
TCC. Management believes, based on advice of counsel, that it is only
reasonably possible that it will ultimately be determined that TCC
should share off-system sales margins after the end of the Texas fuel
factor. However, an adverse ruling could have a material impact on
future results of operations, cash flows and financial condition.
Additional information regarding the 2004 true-up proceeding for TCC can
be found in Note 5 "Customer Choice and Industry Restructuring."
SWEPCo Texas Fuel Reconciliation
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This
reconciliation covers the period of January 2000 through December 2002.
At December 31, 2002, SWEPCo's filing detailed a $2.2 million
over-recovery balance including interest. During the reconciliation
period, SWEPCo incurred $434.8 million of eligible fuel expense. Any
ruling by the PUCT preventing recovery of SWEPCo's fuel costs could have
a material impact on future results of operations, cash flows and
financial condition. Intervenor and PUCT Staff recommendations will be
filed in November 2003 and hearings are scheduled for January 2004.
ERCOT Price-to-Beat (PTB) Fuel Factor Appeal
Several parties including the Office of Public Utility Counsel (OPC) and
cities served by both TCC and TNC appealed the PUCT's December 2001
orders establishing initial PTB fuel factors for Mutual Energy CPL and
Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
lacked sufficient evidence to include unaccounted for energy in the fuel
factor, and that the PUCT improperly shifted the burden of proof and the
record lacked substantial evidence on the effect of loss of load due to
retail competition on generation requirements. The Court upheld the
initial PTB orders on all other issues. In the Mutual Energy CPL
proceeding, the Court ruled that the PUCT improperly shifted the burden
of proof and the record lacked substantial evidence on the effect of
loss of load due to retail competition on generation requirements. The
Court remanded the cases to the PUCT for further proceedings consistent
with its ruling. The amount of unaccounted for energy built into the PTB
fuel factors was approximately $2.7 million for Mutual Energy WTU. At
this time, management is unable to estimate the potential financial
impact related to the loss of load issue. Management appealed the
District Court decisions to the Third Court of Appeals and believes,
based on the advice of counsel, that the PUCT's original decision will
ultimately be upheld. If the District Court's decisions are ultimately
upheld, the PUCT could reduce the PTB fuel factors charged to retail
customers in 2002 and 2003 resulting in an adverse effect on future
results of operations and cash flows.
Unbundled Cost of Service (UCOS) Appeal
TCC placed new transmission and distribution rates into effect as of
January 1, 2002 based upon an order issued by the PUCT resulting from an
UCOS proceeding. TCC requested and received approval from the FERC of
wholesale transmission rates determined in the UCOS proceeding. The UCOS
proceeding set the regulated wires rates to be effective when retail
electric competition began. Regulated delivery charges include the
retail transmission and distribution charge including a nuclear
decommissioning fund charge and a municipal franchise fee, a system
benefit fund fee, a transition charge associated with securitization of
regulatory assets and a credit for excess earnings. Certain rulings of
the PUCT in the UCOS proceeding, including the initial determination of
stranded costs, the requirement to refund TCC's excess earnings,
regulatory treatment of nuclear insurance and distribution rates charged
municipal customers, were appealed to the Travis County District Court
by TCC and other parties to the proceeding. The District Court issued a
decision on June 16, 2003, upholding the PUCT's UCOS order with one
exception. The Court ruled that the refund of the 1999 through 2001
excess earnings solely as a credit to non-bypassable transmission and
distribution rates charged to REPs discriminates against residential and
small commercial customers and is unlawful. The distribution rate credit
began in January 2002. This decision could potentially affect the PTB
rates charged by the AEP REP (Mutual Energy CPL) and could result in a
refund to certain of its customers. Mutual Energy CPL was a subsidiary
of AEP until December 23, 2002 when it was sold. Management estimates
that the effect of reducing the PTB rates for the period prior to the
sale is approximately $11 million pre-tax. Management has appealed this
decision and, based on advice of counsel, believes that it will
ultimately prevail on appeal. If the District Court's decision is
ultimately upheld on appeal, it could have an adverse effect on future
results of operations and cash flows.
McAllen Rate Review
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates
should not be reduced. Other municipalities served by TCC passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC has a minimum of 120 days to provide
support for its rates to the municipalities. TCC has the right to appeal
any rate change by the municipalities to the PUCT. Pursuant to an
agreement with the cities, TCC filed the requested support for its rates
(test year ending June 30, 2003) with both the cities and the PUCT on
November 3, 2003. TCC filed to decrease its wholesale transmission rates
by $2 million or 2.5% and increase its retail energy delivery rates by
$69 million or 19.2%. Management is unable to predict the ultimate
effect of this proceeding on TCC's rates or its impact on TCC's results
of operations, cash flows and financial condition.
Louisiana Fuel Audit
The LPSC is performing an audit of SWEPCo's historical fuel costs. In
addition, five SWEPCo customers filed a suit in the Caddo Parish
District Court in January 2003 and filed a complaint with the LPSC. The
customers claim that SWEPCo has over charged them for fuel costs since
1975. The LPSC consolidated the customer complaint and audit. A
procedural schedule has been developed requiring LPSC Staff and
intervenor testimony be filed in January 2004. Management believes that
SWEPCo's fuel costs prior to 1999 were proper and have been approved by
the LPSC and that SWEPCo's historical fuel costs are reasonable. If the
actions of the LPSC or the Court result in a material disallowance of
recovery of SWEPCo's fuel costs from customers, it could have an adverse
impact on results of operations and cash flows.
FERC Wholesale Fuel Complaints
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), certain TNC wholesale customers filed a
complaint with FERC alleging that TNC had overcharged them through the
fuel adjustment clause for certain purchased power costs since 1997.
Negotiations to settle the complaint and update the contracts have
resulted in new contracts. Consequently, an offer of settlement was
filed at FERC in June 2003 regarding the fuel complaint and new
contracts. Management is unable to predict whether FERC will approve
this offer of settlement, but it is not expected to have a significant
impact on TNC's financial condition. In March 2002, TNC recorded a
provision for refund of $2.2 million before income taxes. TNC
anticipates that the provision for refund will be adequate to cover the
financial implications resulting from these new contracts. Should FERC
fail to approve the settlement and new contracts, the actual refund and
final resolution of this matter could differ materially from the
provision and may have a negative impact on future results of
operations, cash flows and financial condition.
Environmental Surcharge Filing
In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million)
to recover the cost of emissions control equipment being installed at
Big Sandy Plant. See NOx Reductions in Note 6.
In March 2003, the KPSC granted approximately $18 million of the
request. Annual rate relief of $1.7 million was effective in May 2003
and an additional $16.2 million was effective in July 2003. The recovery
of such amounts is intended to offset KPCo's cost of compliance with the
Clean Air Act.
PSO Rate Review
In February 2003, the Director of the OCC filed an application requiring
PSO to file all documents necessary for a general rate review before
August 1, 2003 (revised to October 31, 2003). In October 2003, PSO filed
the required data for this case and requested an increase of $36 million
annually, which is an 8.7% increase over existing base rates. A
procedural schedule has not been set for this case. Management is unable
to predict the ultimate effect of this review on PSO's rates or its
impact on PSO's results of operations, cash flows and financial
condition.
PSO Fuel and Purchased Power
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million
under-recovery of fuel costs resulting from a reallocation in 2002 of
purchased power costs for periods prior to January 1, 2002. On July 23,
2003, PSO filed with the OCC seeking recovery of the $44 million over an
eighteen-month time period. In August 2003, the OCC Staff filed
testimony recommending recovery of $42.4 million ($44 million less two
audit adjustments) over three years. In September 2003, the OCC expanded
the case to include a full prudence review of PSO's 2001 fuel and
purchased power practices. If the OCC does not permit recovery of the
$42.4 million or determines, as a result of the review, that material
fuel and purchased power cost should not be recovered, there will be an
adverse effect on PSO's results of operations, cash flows and possibly
financial condition.
Virginia Fuel Factor Filing
APCo filed with the Virginia SCC to reduce its fuel factor effective
August 1, 2003. The requested fuel rate reduction would be effective for
17 months and is estimated to reduce revenues by $36 million during that
17-month period. By order dated July 23, 2003, the Virginia SCC approved
APCo's requested fuel factor reduction on an interim basis, subject to
further investigation. No other parties to the proceeding have raised
any issues with respect to APCo's request and the Virginia SCC Staff has
filed testimony recommending that APCo's request be approved. This fuel
factor adjustment will reduce cash flows without impacting results of
operations as any over-recovery or under-recovery of fuel costs would be
deferred as a regulatory liability or a regulatory asset. A hearing on
this matter was held on November 5, 2003.
FERC Long-term Contracts
In September 2002, the FERC voted to hold hearings to consider requests
from certain wholesale customers located in Nevada and Washington to
break long-term contracts which they allege are "high-priced." At issue
are long-term contracts entered into during the California energy price
spike in 2000 and 2001. The complaints allege that AEP sold power at
unjust and unreasonable prices. The FERC delayed hearings to allow the
parties to hold settlement discussions. In January 2003, the FERC
settlement judge indicated that the parties' settlement efforts were not
progressing and he recommended that the complaint be placed back on the
schedule for a hearing. In February 2003, AEP and one of the customers
agreed to terminate their contract. The customer withdrew its FERC
complaint and paid $59 million to AEP. As a result of the contract
termination, AEP reversed $69 million of unrealized mark-to-market gains
previously recorded, resulting in a $10 million pre-tax loss.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in
favor of AEP and dismissed, in December 2002, a complaint filed by two
Nevada utilities. In 2000 and 2001, we agreed to sell power to the
utilities for future delivery. In late 2001, the utilities filed
complaints that the prices for power supplied under those contracts
should be lowered because the market for power was allegedly
dysfunctional at the time such contracts were consummated. The ALJ
rejected the utilities' complaint, held that the markets for future
delivery were not dysfunctional, and that the utilities had failed to
demonstrate that the public interest required that changes be made to
the contracts. At a hearing held in April 2003, the utilities asked FERC
to void the long-term contracts. In June 2003, the FERC issued an order
affirming the ALJ's decision and denying the utilities' complaint. The
utilities requested a rehearing. In August 2003, the FERC granted the
request for rehearing. Management is unable to predict the outcome of
this proceeding or its impact on future results of operations and cash
flows.
RTO Formation/Integration Costs
With FERC approval, AEP East companies have been deferring costs
incurred under FERC orders to form an RTO (the Alliance RTO) or join an
existing RTO (PJM). In July 2003, the FERC issued an order approving our
continued deferral of both our Alliance formation costs and our PJM
integration costs including the deferral of a carrying charge. The AEP
East companies have deferred approximately $24 million of RTO formation
and integration costs and related carrying charges through September 30,
2003. As a result of the subsequent delay in the integration of AEP's
East transmission system into PJM, FERC declined to rule, in its July
order, on our request to transfer the deferrals to regulatory assets,
and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies will apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration
with PJM. In August 2003, the Virginia SCC filed a request for rehearing
of the July order, arguing that FERC's action was an infringement on
state jurisdiction, and that FERC should not have treated Alliance RTO
startup costs in the same manner as PJM integration costs. On October
22, 2003, FERC denied the rehearing request.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO until after June 30, 2004 and only
then with the approval of the Virginia SCC. In July 2003, the KPSC
denied KPCo's request to join PJM based in part on a lack of evidence
that it would benefit Kentucky retail customers. In August 2003, KPCo
sought and was granted a rehearing allowing us to submit additional
evidence. A hearing date has not been scheduled.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to
certain conditions included in the order. The IURC's order stated that
AEP shall request and the IURC shall complete a review of Alliance
formation costs ($2 million for I&M) before any deferral of the costs
for future recovery. On September 30, 2003, AEP filed a petition for
reconsideration of the IURC's order, asking the IURC to clarify that its
discussion of the Alliance formation costs was not intended to cause an
immediate write-off of the Indiana retail portion of these costs.
In its July 2003 order, FERC indicated that it would review the deferred
costs at the time they are transferred to a regulatory asset account and
scheduled for amortization and recovery in the open access transmission
tariff (OATT) to be charged by PJM. Management believes that the FERC
will grant permission for the deferred RTO costs to be amortized and
included in the OATT. Whether the amortized costs will be fully
recoverable depends upon the state regulatory commissions' treatment of
AEP East companies' portion of the OATT at the time they join PJM.
Presently, retail rates are frozen or capped and cannot be increased for
retail customers of CSPCo, I&M and OPCo. APCo's base rates are capped
with no changes possible prior to January 1, 2004. We intend to file an
application with FERC seeking permission to delay the amortization of
the deferred RTO formation/integration costs until they are recoverable
from all users of the transmission system including retail customers.
Management is unable to predict the timing of when AEP will join PJM and
if upon joining PJM whether FERC will grant a delay of recovery until
the rate caps and freezes end. If 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). Management intends to seek
recovery of the deferred RTO formation/integration costs and project
implementation cost reimbursements, if incurred. If the FERC ultimately
decides not to approve a delay or the state commissions deny recovery,
future results of operations and cash flows could be adversely affected.
FERC Order on Regional Through and Out Rates
On July 23, 2003, the FERC issued an order directing PJM and the Midwest
ISO to make compliance filings for their respective Open Access
Transmission Tariffs to eliminate, by November 1, 2003, the Regional
Through and Out Rates (RTOR) on transactions where the energy is
delivered within the Midwest ISO and PJM regions (RTO Footprint). In
October 2003, the FERC postponed the November 1, 2003 deadline to
eliminate RTOR. The elimination of the RTORs will reduce the
transmission service revenues collected by the RTOs and thereby reduce
the revenues received by transmission owners under the RTOs' revenue
distribution protocols. The order provided that affected Transmission
Owners could file to offset the elimination of these revenues by
increasing rates or utilizing a transitional rate mechanism to recover
lost revenues that result from the elimination of the RTORs. The FERC
also found that the RTOR of some of the former Alliance RTO Companies,
including AEP, may be unjust, unreasonable, and unduly discriminatory or
preferential for energy delivered in the Midwest ISO/PJM regions. FERC
has initiated an investigation and hearing in regard to these rates. We
made a filing with the FERC supporting the justness and reasonableness
of our rates in August 2003 and made a joint filing with unaffiliated
utilities, on October 14, 2003, proposing a regional revenue replacement
mechanism for the lost revenues, in the event that FERC eliminates AEP's
ability to collect RTOR in the RTO Footprint. Also on October 14, 2003,
FERC issued an order delaying the November 1, 2003 elimination of RTORs
without setting a new date for such elimination. The AEP East companies
received approximately $150 million of RTOR revenues from transactions
delivering energy to customers in the RTO Footprint for the twelve
months ended June 30, 2003. At this time, management is unable to
predict the ultimate outcome of this investigation, or its impact on our
future results of operations, cash flows and financial condition.
Indiana Fuel Order
On July 17, 2003, I&M filed a fuel adjustment clause application
requesting authorization to implement the fixed fuel adjustment charge
(fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage)
for electric service for the billing months of October 2003 through
February 2004, and for approval of a new fuel cost adjustment credit for
electric service to be applicable during the March 2004 billing month.
On August 27, 2003, the IURC issued an order approving the requested
fixed fuel adjustment charge for October 2003 through February 2004. The
order further stated that certain parties must negotiate the appropriate
action on fuel to commence on March 1, 2004. The IURC deferred ruling on
the March 2004 factor until after January 1, 2004.
Michigan 2004 Fuel Recovery Plan
The MPSC's December 16, 1999 order approved a Settlement Agreement
regarding the extended outage of the Cook Plant and fixed I&M Power
Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers
rate areas through December 2003. In accordance with the settlement,
PSCR Plan cases were not required to be filed through the 2003 plan
year. For the 2004 plan year, I&M was required to file a PSCR Plan case
with the MPSC by September 30, 2003. I&M filed its 2004 PSCR Plan with
the MPSC on September 30, 2003 seeking new fuel and power supply
recovery factors to be effective in 2004.
5. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), retail customer choice began in four of
the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which the AEP domestic electric utility companies operate.
The following paragraphs discuss significant events occurring in 2003
related to customer choice and industry restructuring.
Ohio Restructuring
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
Users-Ohio and American Municipal Power-Ohio filed a complaint with the
PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
regarding implementation of their transition plan and violated other
applicable law by failing to participate in an RTO.
The complainants seek, among other relief, an order from the PUCO:
o suspending collection of transition charges by CSPCo and OPCo until
transfer of control of their transmission assets has occurred
o requiring the pricing of standard offer electric generation
effective January 1, 2006 at the market price used by CSPCo and
OPCo in their 1999 transition plan filings to estimate
transition costs and
o imposing a $25,000 per company forfeiture for each day AEP
fails to comply with its commitment to transfer control of
transmission assets to an RTO
Due to the FERC's reversal of its previous approval of our RTO filings
and state legislative and regulatory developments, CSPCo and OPCo have
been delayed in the implementation of their RTO participation plans. We
continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo
filed an application with the PUCO for approval of the transfer of
functional control over certain of their transmission facilities to
PJM. In February 2003, the PUCO consolidated the June complaint with
our December application. CSPCo's and OPCo's motion to dismiss the
complaint has been denied by the PUCO and the PUCO affirmed that ruling
in rehearing. All further action in the consolidated case has been
stayed "until more clarity is achieved regarding matters pending at the
FERC and elsewhere." Management is currently unable to predict the
timing of the AEP East companies' (including CSPCo and OPCo)
participation in PJM, or the outcome of these proceedings before the
PUCO.
On March 20, 2003, the PUCO commenced a statutorily required
investigation concerning the desirability, feasibility and timing of
declaring retail ancillary, metering or billing and collection service,
supplied to customers within the certified territories of electric
utilities, a competitive retail electric service. The PUCO sent out a
list of questions and set June 6, 2003 and July 7, 2003, as the dates
for initial responses and replies, respectively. CSPCo and OPCo filed
comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this
proceeding.
The Ohio Act provides for a Market Development Period (MDP) during
which retail customers can choose their electric power suppliers or
receive Default Service at frozen generation rates from the incumbent
utility. The MDP began on January 1, 2001 and is scheduled to terminate
no later than December 31, 2005. The PUCO may terminate the MDP for one
or more customer classes before that date if it determines either that
effective competition exists in the incumbent utility's certified
territory or that there is a twenty percent switching rate of the
incumbent utility's load by customer class. Following the MDP, retail
customers will receive distribution and transmission service from the
incumbent utility whose distribution rates will be approved by the PUCO
and whose transmission rates will be approved by the FERC. Retail
customers will continue to have the right to choose their electric
power suppliers or receive Default Service, which must be offered by
the incumbent utility at market rates. The PUCO has circulated a draft
of proposed rules but has not yet identified the method by which it
will determine market rates for Default Service following the MDP.
As provided in stipulation agreements approved by the PUCO, we are
deferring customer choice implementation costs that are in excess of
$40 million. The agreements provide for the deferral of these costs as
a regulatory asset until the next distribution base rate cases. At
September 30, 2003, we have incurred $65 million and deferred $25
million of such costs. Recovery of these regulatory assets will be
subject to PUCO review in our next Ohio filings for new distribution
rates. Approved rates will not become effective prior to 2009 for CSPCo
and 2008 for OPCo. Management believes that the customer choice
implementation costs were prudently incurred and the deferred amounts
should be recoverable in future rates. If the PUCO determines that any
of the deferred costs are unrecoverable, it would have an adverse
impact on future results of operations and cash flows.
Texas Restructuring
On January 1, 2002, customer choice of electricity supplier began in
the ERCOT area of Texas. Customer choice has been delayed in other
areas of Texas including the SPP area in which SWEPCo operates. In May
2003, the PUCT approved a stipulation that delays competition in the
SPP area until at least January 1, 2007.
A 2004 true-up proceeding will determine the amount and recovery of
stranded plant costs as of December 31, 2001 including certain
environmental costs incurred by May 1, 2003, final deferred fuel
balance, net generation-related regulatory assets, unrefunded
accumulated excess earnings, excess of price-to-beat revenues over
market prices subject to certain conditions and limitations (Retail
clawback), a true-up of the power costs used in the PUCT's ECOM model
for 2002 and 2003 to reflect actual market prices determined through
legislatively-mandated capacity auctions (wholesale capacity auction
true-up) and other restructuring true-up issues.
The Texas Legislation provides for an earnings test each year from 1999
through 2001 and requires PUCT approval of the annual earnings test
calculation. TCC, TNC and SWEPCo had appealed the PUCT's Final 2000
Earnings Test Order to the Texas Court of Appeals. In August 2003, the
Appeals Court reversed the PUCT order and the district court judgment
affirming it and remanded the controversy back to the PUCT for
proceedings consistent with the Appeals Court's decision. The PUCT
requested rehearing of the Court of Appeal's decision. Our appeal of
the same issue from the PUCT's 2001 Order is pending before the
District Court. Since an expense and regulatory liability had been
accrued in prior years in compliance with the PUCT Final Orders, the
companies reversed a portion of their regulatory liability and credited
amortization expense during the third quarter of 2003. Pre-tax amounts
by company were $5.1 million for TCC, $2.6 million for TNC and $1.1
million for SWEPCo.
The Texas Legislation provides for the affiliated PTB REP to refund to
its transmission and distribution (T&D) utility the excess of the PTB
revenues over market prices (subject to certain conditions and a
limitation of $150 per customer). This is the retail clawback. The
retail clawback regulatory liability is to be included in the 2004
true-up proceedings and netted against other true-up adjustments. If
40% of the load for the residential or small commercial classes is
served by competitive REPs, the retail clawback is not applicable for
that class of customer. In July 2003, TCC and TNC filed to notify the
PUCT that competitive REPs serve over 40% of the load in the small
commercial class. On August 21, 2003, the PUCT dismissed these filings
and ruled that TCC and TNC should refile no sooner than September 22,
2003 in order to establish the required notice period. TCC and TNC
refiled in late September 2003. In October 2003, the PUCT Staff
recommended approval of TCC's application and denial of TNC's
application. The PUCT Staff determined that only 39.9% of TNC's small
commercial customers were served by competitive REPs as of the end of
August 2003. If the PUCT denies TNC's application, TNC will likely meet
the 40% threshold in September 2003 and refile its application. AEP had
accrued a regulatory liability of approximately $9 million for the
small commercial retail clawback on its REP's books. If the PUCT
certifies that TCC and/or TNC have reached the 40% threshold, the
regulatory liability would no longer be required for the small
commercial class and could be reversed.
The Texas Legislation allows for several alternative methods to be used
to value stranded generation assets in the 2004 true-up proceeding
including the sale or exchange of generation assets, stock valuation
methods or the use of an ECOM model for nuclear generation assets. TCC
is the only AEP subsidiary that has stranded costs under the Texas
Legislation.
In the fourth quarter of 2002, TCC decided to determine the market
value of its generating assets through the sale of those assets for
purposes of determining stranded costs for the 2004 true-up proceeding.
In December 2002, TCC filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. The
amount of stranded costs under this market valuation methodology will
be the amount by which the book value of TCC's generating assets,
including regulatory assets and liabilities that were not securitized,
exceeds the market value of the generation assets as measured by the
net proceeds from the sale of the assets. It is anticipated that any
such sale will result in significant stranded costs for purposes of
TCC's 2004 true-up proceeding. The filing included a request for the
PUCT to issue a declaratory order that TCC's 25.2% ownership interest
in its nuclear plant, STP, can be sold to establish its market value
for determining stranded plant costs. Intervenors to this proceeding,
including the PUCT Staff, made filings to dismiss TCC's filing claiming
that the PUCT does not have the authority to issue such a declaratory
order. The intervenors also argued that the proper time to address the
sales process is after the plants are sold during the 2004 true-up
proceeding. Since the closing process for the plants sold is not
expected to be completed before mid-2004, TCC requested that its 2004
true-up proceeding be scheduled after completion of the divestiture of
its generating assets.
In March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address allowable valuation methods for
the nuclear asset in a rulemaking proceeding. The PUCT approved a rule,
in May 2003, which allows the market value obtained by selling nuclear
assets to be used in determining stranded costs. The PUCT dismissed
TCC's request to certify its proposed divestiture plan; therefore its
divestiture plan will be subject to a review in the 2004 true-up
proceeding. The PUCT adopted a rule regarding the timing of the 2004
true-up proceedings scheduling TNC's filing in May 2004 and TCC's
filing in September 2004 or 60 days after the completion of the sale of
TCC's generation assets, if later.
Texas Legislation also requires that electric utilities and their
affiliated power generation companies (PGC) sell at auction in 2002 and
2003 at least 15% of the PGC's Texas jurisdictional installed
generation capacity in order to promote competitiveness in the
wholesale market through increased availability of generation. Actual
market power prices received in the state mandated auctions will
replace the PUCT's earlier estimates of those market prices for 2002
and 2003 used in the ECOM model to calculate the wholesale capacity
auction true-up adjustment for TCC for the 2004 true-up proceeding.
The decision to determine stranded costs by selling TCC's generating
plants and the expectation that the sales price would produce a
significant loss/stranded cost instead of using the PUCT's ECOM model
negative stranded cost estimate, enabled TCC to record in 2002 a $262
million regulatory asset and related revenues which represents the
quantifiable amount of the wholesale capacity auction true-up for the
year 2002. Through September 30, 2003, TCC recorded an additional $169
million regulatory asset and related revenues for wholesale capacity
auction true-up. Prior to the decision to pursue a sale of TCC's
generating assets, the PUCT's negative ECOM estimate prohibited the
recognition of the regulatory assets and revenues, as they cannot be
recovered unless there are stranded costs. However, in March 2003, the
Texas Court of Appeals ruled that under the restructuring legislation,
other 2004 true-up items including the wholesale capacity auction
true-up regulatory asset, could be recovered regardless of the level of
stranded plant costs.
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 has
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.
When the plant divestitures and the 2004 true-up proceeding are
completed, TCC will file to recover PUCT-approved stranded costs and
other true-up amounts that are in excess of current securitized amounts
plus a carrying charge through a non-bypassable competition transition
charge in rates of the regulated T&D utility. In addition, TCC may seek
to securitize certain of the approved stranded plant costs and
regulatory assets, not previously recovered through the non-bypassable
transition charge. The annual costs of securitization are recovered
through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.
In the event we are unable, after the 2004 true-up proceeding, to
recover all or a portion of our generation-related regulatory assets,
unrecovered fuel balances, stranded plant 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.
Arkansas Restructuring
In February 2003, Arkansas repealed customer choice legislation
originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
reapplied SFAS 71 regulatory accounting, which had been discontinued in
1999. The reapplication of SFAS 71 had an insignificant effect on
results of operations and financial condition. As a result of
reapplying SFAS 71, derivative contract gains/losses for transactions
within AEP's traditional marketing area allocated to Arkansas will not
affect income until settled. That is, such positions will be recorded
on the balance sheet as either a regulatory asset or liability until
realized.
West Virginia Restructuring
APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
first quarter of 2003 after new developments during the quarter
prompted an analysis of the probability of restructuring becoming
effective.
In 2000, the WVPSC issued an order approving an electricity
restructuring plan, which the WV Legislature approved by joint
resolution. The joint resolution provided that the WVPSC could not
implement the plan until the WV legislature made tax law changes
necessary to preserve the revenues of state and local governments.
In the 2001 and 2002 legislative sessions, the WV Legislature failed to
enact the required legislation that would allow the WVPSC to implement
the restructuring plan. Due to this lack of legislative activity, the
WVPSC closed two proceedings related to electricity restructuring
during the summer of 2002.
In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, legislation enacted in March 2003
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
restructuring in WV was no longer probable and confirmed facts relating
to the WVPSC's jurisdiction and rate authority over APCo's WV
generation. APCo has concluded that deregulation of the WV generation
business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.
Reapplying SFAS 71 in WV had an insignificant effect on results of
operations and financial condition. As a result, derivative contract
gains/losses related to transactions within AEP's traditional marketing
area allocated to WV will not affect income until settled. That is,
such positions will be recorded on the balance sheet as either a
regulatory asset or liability until realized. Positions outside AEP's
traditional marketing area will continue to be marked-to-market.
6. COMMITMENTS AND CONTINGENCIES
-----------------------------
Power Generation Facility
AEP has agreements with Juniper Capital L.P. (Juniper) under which
Juniper will develop, construct, and finance a power generation facility
(Facility) near Plaquemine, Louisiana and lease the Facility to AEP.
Construction of the Facility was begun by Katco Funding, Limited
Partnership (Katco), an unrelated unconsolidated special purpose entity,
and Katco assigned its interest in the Facility to Juniper in June 2003.
Juniper is a limited partnership, unaffiliated and unconsolidated with
AEP, formed to construct or otherwise acquire real and personal property
for lease to third parties, to manage financial assets and to undertake
other activities related to asset financing. Juniper has arranged to
finance the Facility with debt financing up to $494 million and equity
up to $31 million (approximately 6%) of the Facility's acquisition cost
from investors with no relationship to AEP or any of AEP's subsidiaries.
Juniper will own the Facility and lease it to AEP after construction is
completed. The lease will be treated as an operating lease for financial
accounting purposes. Consequently, the Facility and the related
obligations are not reported on AEP's Consolidated Balance Sheet.
Payments under the operating lease are expected to commence in the first
quarter of 2004. AEP will in turn sublease the Facility to Dow Chemical
Company (DOW). The use of Juniper allows AEP to limit its risk
associated with the Facility once construction has been completed. In
addition, the lease allows AEP to utilize certain tax benefits
associated with the Facility.
In the event the project is terminated before completion of
construction, AEP has the option to either purchase the Facility for
100% of Juniper's acquisition cost (in general, the outstanding debt and
equity associated with the Facility) or terminate the project and make a
payment to Juniper for 89.9% of project costs (in general, the
acquisition cost less certain financing costs.)
DOW will use a portion of the energy produced by the Facility and sell
the excess energy. AEP has agreed to purchase approximately 800 MW of
such excess energy from DOW. AEP has also agreed to sell approximately
800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period
of 20 years under a Power Purchase and Sale Agreement dated November 15,
2002 (PPA) at a price which is currently in excess of market. Beginning
May 1, 2003, AEP was obligated pursuant to the PPA to provide
replacement capacity, energy and ancillary services to TEM. TEM has
rejected as non-conforming the replacement capacity, energy and
ancillary services tendered by AEP.
On September 5, 2003, TEM and AEP separately filed declaratory judgment
actions in the United State District Court for the Southern District of
New York. Both suits seek a declaration from the Court of the parties'
respective rights under the PPA. AEP alleges that TEM has breached the
PPA. TEM alleges that the PPA is unenforceable or alternatively, that
AEP has breached the PPA. If the PPA is terminated or found to be
unenforceable, AEP could be adversely affected to the extent we are
unable to find other purchasers of the power with similar contractual
terms including comparable levels of profitability.
AEP is the construction agent for Juniper. Construction is currently
scheduled to be completed by the first quarter of 2004. If the Facility
is not completed by April 30, 2004, TEM may claim that it can terminate
the PPA and is owed liquidating damages of approximately $17.5 million.
The initial term of the operating lease between Juniper and AEP
commences on the commercial operation date (COD) of the Facility and
continues for five years or, if earlier, until June 2009. The lease
contains extension options and if all extension options were exercised,
the total term of the lease would be 30 years. AEP's lease payments to
Juniper during the initial term and each extended term are sufficient
for Juniper to make required debt payments under Juniper's debt
financing associated with the Facility and provide a return on equity to
the investors in Juniper. AEP has the right to purchase the Facility for
the acquisition cost during the last month of the initial term or on any
monthly rent payment date during any extended term. In addition, AEP may
purchase the Facility from Juniper for the acquisition cost at any time
during the initial term if AEP has arranged a sale of the Facility to an
unaffiliated third party. A purchase of the Facility from Juniper by AEP
should not alter DOW's rights to lease the Facility or AEP's contract to
purchase energy from DOW. If the lease were renewed for up to a 30-year
lease term, AEP may renew the lease at fair market value subject to
Juniper's approval, purchase the Facility at its original construction
cost, or sell the Facility, on behalf of Juniper, to an independent
third party. If the Facility is sold and the proceeds from the sale are
insufficient to pay all of Juniper's acquisition costs, we may be
required to make a payment (not to exceed $396 million) to Juniper of
the excess of Juniper's acquisition costs over the proceeds from the
sale, provided that AEP would not be required to make any payment if AEP
has made the additional rental prepayment described below. AEP has
guaranteed the performance of its subsidiaries to Juniper during the
lease term. Due to FIN 45, at COD, AEP will be required to record the
fair value (approximately $35 million) of this guarantee as a liability
with an offsetting asset.
As of September 30, 2003, Juniper's acquisition costs for the Facility
totaled $460 million, and total costs for the completed Facility are
currently expected to be approximately $525 million. For the 30-year
extended lease term, the base lease rental is a variable rate obligation
indexed to three-month LIBOR. Consequently as market interest rates
increase, the base rental payments under this operating lease will also
increase. Annual payments of approximately $18 million represent future
minimum payments during the initial term calculated using the indexed
LIBOR rate (1.14% at September 30, 2003). An additional rental
prepayment (up to $396 million as of September 30, 2003) may be due on
June 30, 2004 unless Juniper has refinanced its present debt financing
on a long-term basis. The Facility is collateral for the debt obligation
of Juniper. Our maximum exposure to loss as a result of our financing
transaction with Juniper is 89.9% of Juniper's project costs during the
construction phase and up to $396 million once the construction is
completed. These calculations could change based on the final amount of
total costs or changes in interest rates. Maximum loss is deemed to be
remote due to the collateralization.
As a result of Katco's transfer of its interest in the Facility to
Juniper, we did not consolidate Juniper or any portion of the Facility
in accordance with FIN 46.
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.
Federal EPA Complaint and Notice of Violation
As discussed in Note 9 of the Combined Notes to Financial Statements 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 modified certain 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.
Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might
be triggered and the plant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant. The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997). In
2001, the District Court ruled claims for civil penalties based on
activities that occurred more than five years before the filing date of
the complaints cannot be imposed. There is no time limit on claims for
injunctive relief.
On August 7, 2003, the District Court issued a decision following a
liability trial in a case pending in the Southern District of Ohio
against Ohio Edison Company, an unaffiliated utility. The District Court
held that replacements of major boiler and turbine components that are
infrequently performed at a single unit, that are performed with the
assistance of outside contractors, that are accounted for as capital
expenditures, and that require the unit to be taken out of service for a
number of months are not "routine" maintenance, repair, and replacement.
The District Court also held that a comparison of past actual emissions
to projected future emissions must be performed prior to any non-routine
physical change in order to evaluate whether an emissions increase will
occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all
of the challenged activities in that case were not routine, and that the
changes resulted in significant net increases in emissions for certain
pollutants. A remedy trial is scheduled for April 2004.
Management believes that the Ohio Edison decision fails to properly
evaluate and apply the applicable legal standards. The facts in our case
also vary widely from plant to plant. Further, the Ohio Edison decision
is limited to liability issues, and provides no insight as to the
remedies that might ultimately be ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South
Carolina issued a decision on cross-motions for summary judgment prior
to a liability trial in a case pending against Duke Energy Corporation,
an unaffiliated utility. The District Court denied all the pending
motions, but set forth the legal standards that will be applied at the
trial in that case. The District Court determined that the Federal EPA
bears the burden of proof on the issue of whether a practice is "routine
maintenance, repair, or replacement" and on whether or not a
"significant net emissions increase" results from a physical change or
change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the
relevant source category" in determining if it is "routine." Further,
the Federal EPA must calculate emissions by determining first whether a
change in the maximum achievable hourly emission rate occurred as a
result of the change, and then must calculate any change in annual
emissions holding hours of operation constant before and after the
change.
On June 24, 2003, the United States Court of Appeals for the 11th
Circuit issued an order invalidating the administrative compliance order
issued by the Federal EPA to the Tennessee Valley Authority for similar
alleged violations. The 11th Circuit determined that the administrative
compliance order was not a final agency action, and that the enforcement
provisions authorizing the issuance and enforcement of such orders under
the Clean Air Act are unconstitutional.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group
(UARG), of which our subsidiaries are members, to reopen petitions for
review of the 1980 and 1992 Clean Air Act rulemakings that are the basis
for the Federal EPA claims in our case and other related cases. On
August 4, 2003, UARG filed a motion to separate and expedite review of
their challenges to the 1980 and 1992 rulemakings from other unrelated
claims in the consolidated appeal. The Circuit Court denied that motion
on September 30, 2003. The central issue in these petitions concerns the
lawfulness of the emissions increase test, as currently interpreted and
applied by the Federal EPA in its utility enforcement actions. A
decision by the D. C. Circuit Court could significantly impact further
proceedings in our case.
On August 27, 2003, the Administrator of the Federal EPA signed a final
rule that defines "routine maintenance repair and replacement" to
include "functionally equivalent equipment replacement." Under the new
final rule, replacement of a component within an integrated industrial
operation (defined as a "process unit") with a new component that is
identical or functionally equivalent will be deemed to be a "routine
replacement" if the replacement does not change any of the fundamental
design parameters of the process unit, does not result in emissions in
excess of any authorized limit, and does not cost more than twenty
percent of the replacement cost of the process unit. The new rule is
intended to have prospective effect, and will become effective in
certain states 60 days after October 27, 2003, the date of its
publication in the Federal Register, and in other states upon completion
of state processes to incorporate the new rule into state law. On
October 27, 2003 twelve states, the District of Columbia and several
cities filed an action in the United States Court of Appeals for the
District of Columbia Circuit seeking judicial review of the new rule.
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.
In December 2000, Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement
with the Federal EPA and other parties to settle litigation regarding
generating plant emissions under the Clean Air Act. Negotiations are
continuing between the parties in an attempt to reach final settlement
terms. Cinergy's settlement could impact the operation of Zimmer Plant
and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
respectively, by CSPCo). Until a final settlement is reached, CSPCo will
be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
NOx Reductions
The Federal EPA issued a NOx Rule requiring substantial reductions in
NOx emissions in a number of eastern states, including certain states in
which the AEP System's generating plants are located. The NOx Rule has
been upheld on appeal. The compliance date for the NOx Rule is May 31,
2004.
In 2000, the Federal EPA also adopted a revised rule (the Section 126
Rule) granting petitions filed by certain northeastern states under the
Clean Air Act. The rule imposes emissions reduction requirements
comparable to the NOx Rule beginning May 1, 2003, for most of our
coal-fired generating units. Affected utilities, including certain AEP
operating companies, petitioned the D.C. Circuit Court to review the
Section 126 Rule.
After review, the D.C. Circuit Court instructed the Federal EPA to
justify the methods it used to allocate allowances and project growth
for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and
other utilities requested that the D.C. Circuit Court vacate the Section
126 Rule or suspend its May 2003 compliance date. In 2001, the D.C.
Circuit Court issued an order tolling the compliance schedule until the
Federal EPA responds to the Court's remand. On April 30, 2002, the
Federal EPA announced that May 31, 2004 is the compliance date for the
Section 126 Rule. The Federal EPA published a notice in the Federal
Register on May 1, 2002 advising that no changes in the growth factors
used to set the NOx budgets were warranted. In June 2002, our
subsidiaries joined other utilities and industrial organizations in
seeking a review of the Federal EPA's actions in the D.C. Circuit Court.
This action is pending.
In 2000, the Texas Commission on Environmental Quality adopted rules
requiring significant reductions in NOx emissions from utility sources,
including TCC and SWEPCo. The compliance requirements began in May 2003
for TCC and begin in May 2005 for SWEPCo.
We are installing a variety of emission control technologies to reduce
NOx emissions to comply with the applicable state and Federal NOx
requirements. This includes selective catalytic reduction (SCR)
technology on certain units and other combustion control technologies on
a larger number of units. During 2001, 2002 and 2003, SCR technology
commenced operations on units of Gavin, Amos, Mountaineer, Big Sandy and
Cardinal plants. Construction of SCR technology at certain other AEP
generating units continues. Other combustion control technologies have
been installed and commenced operation on a number of units across the
AEP System and additional units will be equipped with these technologies.
Our NOx compliance plan is a dynamic plan that is continually reviewed
and revised as new information becomes available on the performance of
installed technologies and the cost of planned technologies. Certain
compliance steps may or may not be necessary as a result of this new
information. Consequently, the plan has a range of possible outcomes.
Current estimates indicate that our compliance with the NOx Rule, the
Texas Commission on Environmental Quality rule and the Section 126 Rule
could result in required capital expenditures in the range of $1.3
billion to $1.7 billion, of which $1 billion has been spent through
September 30, 2003. Since compliance costs cannot be estimated with
certainty, 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 and 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.
Enron Bankruptcy
On October 15, 2002, certain subsidiaries of AEP filed claims against
Enron and its subsidiaries in the bankruptcy proceeding filed by the
Enron entities which are pending in the U.S. Bankruptcy Court for the
Southern District of New York. At the date of Enron's bankruptcy,
certain subsidiaries of AEP had open trading contracts and trading
accounts receivables and payables with Enron. In addition, on June 1,
2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various
HPL related contingencies and indemnities from Enron remained unsettled
at the date of Enron's bankruptcy. The timing of the resolution of the
claims by the Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive
rights to use and operate the underground Bammel gas storage facility
pursuant to an agreement with BAM Lease Company, a now-bankrupt
subsidiary of Enron. This exclusive right to use the referenced facility
is for a term of 30 years, with a renewal right for another 20 years and
includes the use of the Bammel storage facility and the appurtenant
pipelines. We have engaged in preliminary discussions with Enron
concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between
AEP and Enron relating to our acquisition of HPL and the possible
resolution of outstanding energy trading issues. We are unable to
predict whether these discussions will lead to an agreement on these
subjects. If these discussions do not lead to an agreement, Enron may
attempt to reject certain of the agreements relating to the Bammel
storage facility and certain appurtenant pipelines.
We also entered into an agreement with BAM Lease Company which grants
HPL the right to use approximately 65 billion cubic feet of cushion gas
(or pad gas) required for the normal operation of the Bammel gas storage
facility. The Bammel Gas Trust, which purportedly owned approximately 55
billion cubic feet of gas, had entered into a financing arrangement in
1997 with Enron and a group of banks. These banks purported to have
certain rights to gas in certain events of default. In connection with
our acquisition of HPL, the banks entered into an agreement granting
HPL's exclusive use of the 65 billion cubic feet of cushion gas and
released HPL from liabilities and obligations under the financing
arrangement. HPL was thereafter informed by the banks of a purported
default by Enron under the terms of the referenced financing
arrangement. In July 2002, the banks filed a lawsuit against HPL in the
state court of Texas seeking a declaratory judgment that they have a
valid and enforceable security interest in gas purportedly in the Bammel
storage facility which would permit them to cause the withdrawal of gas
from the storage facility. In September 2002, HPL filed a general denial
and certain counterclaims against the banks. HPL also filed a motion to
dismiss, which was denied. Trial is currently scheduled for December
2003. Management is unable to predict the outcome of this lawsuit or
its impact on our results of operations, cash flows and financial
condition.
On October 31, 2003, AEP Energy Services Gas Holding Company filed a
lawsuit against Bank of America in the United States District Court for
the Southern District of Texas. The lawsuit seeks damages for Bank of
America's breach of contract and negligent misrepresentation in
connection with transactions surrounding our acquisition of HPL from
Enron. Bank of America led a lending syndicate involved in financing
transactions that Enron and its subsidiaries undertook, including
transactions that were prior to the sale of HPL and the leasing of the
Bammel underground gas storage reservoir to HPL. The lawsuit asserts
that we purchased HPL and undertook other related actions based on
representations that Bank of America made about Enron's financial
condition that Bank of America knew or should have known were false.
During 2002 and 2001, we expensed a total of $53 million ($34 million
net of tax) for our estimated loss from the Enron bankruptcy. The amount
expensed was based on an analysis of contracts where AEP and Enron
entities are counterparties, the offsetting of receivables and payables,
the application of deposits from Enron entities and management's
analysis of the HPL related purchase contingencies and indemnifications.
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 outcome of this lawsuit or its impact on our results of
operations, cash flows or financial condition.
Shareholder Lawsuits
In the fourth quarter of 2002 and the first quarter of 2003, lawsuits
alleging securities law violations and seeking class action
certification were filed in federal District Court, Columbus, Ohio
against AEP, certain AEP executives, and in some of the lawsuits,
members of the AEP Board of Directors and certain investment banking
firms. The lawsuits claim that we failed to disclose that alleged "round
trip" trades resulted in an overstatement of revenues, that we failed to
disclose that our traders falsely reported energy prices to trade
publications that published gas price indices and that we failed to
disclose that we did not have in place sufficient management controls to
prevent "round trip" trades or false reporting of energy prices. The
plaintiffs seek recovery of an unstated amount of compensatory damages,
attorney fees and costs. The Court has appointed a lead plaintiff who
has filed a Consolidated Amended Complaint. We have filed a Motion to
Dismiss the Consolidated Amended Complaint. Also, in the first quarter
of 2003, a lawsuit making essentially the same allegations and demands
was filed in state Common Pleas Court, Columbus, Ohio against AEP,
certain executives, members of the Board of Directors and our
independent auditor. We removed this case to federal District Court in
Columbus. The case is pending on plaintiff's motion to remand the case
to state court. We intend to continue to vigorously defend against these
actions.
In the fourth quarter of 2002, two shareholder derivative actions were
filed in state court in Columbus, Ohio against AEP and its Board of
Directors alleging a breach of fiduciary duty for failure to establish
and maintain adequate internal controls over our gas trading operations.
These cases have been stayed pending the outcome of our Motion to
Dismiss the Consolidated Amended Complaint in the federal securities
lawsuits. If these cases do proceed, we intend to vigorously defend
against them. Also, in the fourth quarter of 2002 and the first quarter
of 2003, three putative class action lawsuits were filed against AEP,
certain executives and AEP's Employee Retirement Income Security Act
(ERISA) Plan Administrator alleging violations of ERISA in the selection
of AEP stock as an investment alternative and in the allocation of
assets to AEP stock. The ERISA actions are pending in federal District
Court, Columbus, Ohio. In these actions, the plaintiffs seek recovery of
an unstated amount of compensatory damages, attorney fees and costs. We
intend to vigorously defend against these actions.
California Lawsuit
In November 2002, the Lieutenant Governor of California filed a lawsuit
in Los Angeles County, California Superior Court against forty energy
companies, including AEP, and two publishing companies alleging
violations of California law through alleged fraudulent reporting of
false natural gas price and volume information with an intent to affect
the market price of natural gas and electricity. This case is in the
initial pleading stage and all defendants have filed motions to dismiss.
AEP has been dismissed from the case. The plaintiff had stated an
intention to amend the complaint to add an AEP subsidiary as a
defendant. The plaintiff amended the complaint but did not name any AEP
company as a defendant.
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, has filed a lawsuit in
federal District Court in Corpus Christi, Texas against us and four AEP
subsidiaries, certain unaffiliated energy companies and ERCOT. The
action alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made
against the AEP companies, range from anticompetitive bidding to
withholding power. TCE alleges that these activities resulted in price
spikes requiring TCE to post additional collateral and ultimately forced
it into bankruptcy when it was unable to raise prices to its customers
due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary
damages and court costs. This case is in the initial pleading stage. We
have filed a Motion to Dismiss. The Court has set a hearing on the
Motion to Dismiss for January 2004. Management believes that the claims
against us are without merit. We intend to vigorously defend against the
claims.
Bank of Montreal Claim
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
deals and claimed approximately $34 million was owed to BOM by AEP. In
April 2003, we filed a lawsuit in federal District Court in Columbus,
Ohio against BOM claiming BOM had acted contrary to the appropriate
trading contract and industry practice in 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 October 2002, we filed a demand for arbitration with the American
Arbitration Association to initiate formal arbitration proceedings in a
dispute with the Williams Companies (Williams). The proceeding resulted
from Williams' repudiation of its obligations to provide physical power
deliveries to AEP and Williams' failure to provide the monetary security
required for natural gas deliveries by AEP. Consequently, both parties
claimed default and terminated all outstanding natural gas and electric
power trading deals among the various Williams and AEP affiliates.
Williams claimed that we owed approximately $130 million in connection
with the termination and liquidation of all trading deals. Williams and
AEP settled the dispute and we paid $90 million to Williams in June
2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity
using MTM accounting. As a result, the resolution of this matter did not
have a material impact on results of operations or financial condition.
Arbitration of PG&E Energy Trading, LLC Claim
In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately
$22 million was owed by AEP in connection with the termination and
liquidation of all trading deals. In February 2003, PGET initiated
arbitration proceedings. In July 2003, AEP and PGET agreed to a
settlement and we paid approximately $11 million to PGET. The settlement
amount approximated the amount payable that, in the ordinary course of
business, we recorded as part of our trading activity using MTM
accounting. As a result, the settlement payment did not have a material
impact on results of operations, cash flows or financial condition.
Energy Market Investigation
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 asking that we
voluntarily provide information. The subpoena sought additional
information and is part of the SEC's formal investigation. We responded
to the subpoena and will continue to cooperate with the SEC.
On September 30, 2003, the CFTC filed a complaint against AEP and AEPES
in federal district court in Columbus, Ohio. The CFTC alleges that AEP
and AEPES provided false or misleading information about market
conditions and prices of natural gas in an attempt to manipulate the
price of natural gas in violation of the Commodity Exchange Act. The
CFTC seeks civil penalties, restitution and disgorgement of benefits.
The case is in the initial pleading stage. 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.
FERC Proposed Standard Market Design
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, which sought to standardize the structure and
operation of wholesale electricity markets across the country. Key
elements of FERC's proposal included standard rules and processes for
all users of the electricity transmission grid, new transmission rules
and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC issued a
white paper on the proposal in April 2003, in response to the numerous
comments FERC received on its proposal. Until the rule is finalized,
management cannot predict its effect on cash flows and results of
operations.
FERC Proposed Security Standards
As part of the SMD proposed rulemaking, in July 2002, FERC published for
comment proposed security standards. These standards were intended to
ensure that all market participants would have a basic security program
that would effectively protect the electric grid and related market
activities. As proposed, these standards would apply to AEP's power
transmission systems, distribution systems and related areas of
business. The proposed standards have not been adopted. Subsequently, in
2002, the North American Electric Reliability Council (NERC), with
FERC's support, developed a new set of standards to address industry
compliance. These new standards closely parallel the initial, proposed
FERC standards in both content and compliance time frames, and were
approved by the NERC ballot body in June 2003. We have developed
financial requirements for security implementation and compliance with
these NERC standards, the costs of which are not expected to be material
to our future results of operations and cash flows.
7. GUARANTEES
----------
There are no liabilities recorded for guarantees entered into prior to
December 31, 2002 in accordance with FIN 45. There are certain
liabilities recorded for guarantees entered into subsequent to December
31, 2002. These liabilities are immaterial to AEP. There is no
collateral held in relation to any guarantees and there is no recourse
to third parties in the event any guarantees are drawn unless specified
below.
LETTERS OF CREDIT
AEP and certain of its subsidiaries have entered into standby letters of
credit (LOC) with third parties. These LOCs cover gas and electricity
trading contracts, construction contracts, insurance programs, security
deposits, debt service reserves, drilling funds and credit enhancements
for issued bonds. All of these LOCs were issued by AEP or a subsidiary
in the ordinary course of business. At September 30, 2003, the maximum
future payments for all the LOCs are approximately $181 million with
maturities ranging from September 30, 2003 to January 2011. Included in
these amounts is TCC's LOC of approximately $40.9 million with a
maturity date of November 2003. As the parent of all these subsidiaries,
we hold all assets of the subsidiaries as collateral. There is no
recourse to third parties in the event these letters of credit are
drawn.
GUARANTEES OF THIRD-PARTY OBLIGATIONS
CSW Energy and CSW International
CSW Energy and CSW International have guaranteed 50% of the required
debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which
CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny
funding the debt reserve as a part of a financing. In the event that
Sweeny does not make the required debt payments, CSW Energy and CSW
International have a maximum future payment exposure of approximately
$3.7 million, which expires June 2020.
AEP Utilities
AEP Utilities guaranteed 50% of the required debt service reserve for
Polk Power Partners, an IPP of which CSW Energy owns 50%. In the event
that Polk Power does not make the required debt payments, AEP Utilities
has a maximum future payment exposure of approximately $4.7 million,
which expires July 2010.
AEP
AEP has guaranteed 50% of the principal and interest payments as well as
50% of a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which
AEP is a 50% owner. In the event Fort Lupton does not make the required
debt payments, AEP has a maximum future payment exposure of
approximately $6 million, which expires May 2008. In the event Fort
Lupton is unable to perform under its PPA agreement, AEP has a maximum
future payment exposure of approximately $14.8 million, which expires
June 2019.
AEP has guaranteed 50% of a security deposit for gas transmission as
well as 50% of a Power Purchase Agreement (PPA) of Orange Cogeneration
(Orange), an IPP of which AEP is a 50% owner. In the event Orange fails
to make payments in accordance with agreements for gas transmission, AEP
has a maximum future payment exposure of approximately $0.8 million,
which expires June 2023. In the event Orange is unable to perform under
its PPA agreement, AEP has a maximum future payment exposure of
approximately $1.1 million, which expires June 2016.
SWEPCo
In connection with reducing the cost of the lignite mining contract for
its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
conditions, to assume the obligations under a revolving credit
agreement, capital lease obligations, and term loan payments of the
mining contractor, Sabine Mining Company (Sabine). In the event Sabine
defaults under any of these agreements, SWEPCo's total future maximum
payment exposure is approximately $60 million with maturity dates
ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At September 30,
2003, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
On July 1, 2003, SWEPCo consolidated Sabine due to the application of
FIN 46 (see Note 3). Upon consolidation, SWEPCo recorded the assets and
liabilities of Sabine ($77.8 million). Also, after consolidation, SWEPCo
currently records all expenses (depreciation, interest and other
operation expense) of Sabine and eliminates Sabine's revenues against
SWEPCo's fuel expenses. There is no cumulative effect of an accounting
change recorded as a result of the requirement to consolidate, and there
is no change in net income due to the consolidation of Sabine.
Other
See Power Generation Facility section of Note 6 "Commitments and
Contingencies" for disclosure of related guarantees.
INDEMNIFICATIONS AND OTHER GUARANTEES
We entered into several types of contracts, which would require
indemnifications. Typically these contracts include, but are not limited
to, sale agreements, lease agreements, purchase agreements and financing
agreements. Generally these agreements may include, but are not limited
to, indemnifications around certain tax, contractual and environmental
matters. With respect to sale agreements, our exposure generally does
not exceed the sale price. We cannot estimate the maximum potential
exposure for any of these indemnifications entered into prior to
December 31, 2002 due to the uncertainty of future events. In the first
nine months of 2003, we entered into several sale agreements discussed
in Note 8. These sale agreements include indemnifications with a maximum
exposure of approximately $67 million. There are no material liabilities
recorded for any indemnifications entered into during the first nine
months of 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.
We lease certain equipment under a master operating lease. Under the
lease agreement, the lessor is guaranteed to receive up to 87% of the
unamortized balance of the equipment at the end of the lease term. If
the fair market value of the leased equipment is below the unamortized
balance at the end of the lease term, we have committed to pay the
difference between the fair market value and the unamortized balance,
with the total guarantee not to exceed 87% of the unamortized balance.
At September 30, 2003, the maximum potential loss for these lease
agreements was approximately $27 million assuming the fair market value
of the equipment is zero at the end of the lease term.
See Note 10 "Leases" for disclosure of lease residual value guarantees.
8. DISPOSITIONS, DISCONTINUED OPERATIONS, ASSETS HELD FOR SALE AND IMPAIRMENTS
---------------------------------------------------------------------------
DISPOSITIONS
Dispositions During the First Half of 2003
During the first six months of 2003, we completed the sales of C3
Communications, Mutual Energy Service Company, LLC, our Newgulf
facility, our Nordic Trading business, our water heater rental program
assets and our interest in AEP Gas Power Systems, LLC. The impact on our
results of operations for the third quarter and for the nine months
ended September 30, 2003 was not significant.
Eastex
We completed the sale of Eastex during the third quarter of 2003. We
provided for a $218.7 million pre-tax asset impairment in the fourth
quarter 2002, and the effect of the sale on third quarter 2003 results
of operations was not significant. The results of operations of Eastex
have been reclassified as Discontinued Operations in accordance with
SFAS 144. The assets and liabilities of Eastex were reclassified on the
Consolidated Balance Sheets from Assets Held for Sale and Liabilities
Held for Sale to Discontinued Operations at December 31, 2002. The
balance sheet components consisted of Current Assets of $15 million,
Current Liabilities of $8 million and Other Liabilities of $4 million.
DISCONTINUED OPERATIONS
The results of operations of the entities shown below, affecting AEP,
have been reclassified as Discontinued Operations for all periods
presented. The assets and liabilities of Pushan Power Plant were
aggregated on our Consolidated Balance Sheets as Assets Held for Sale
and Liabilities Held for Sale (see table at the end of the Assets Held
for Sale section below for more detailed information):
For the quarter ended September 30, 2003 and 2002:
Pushan Power
SEEBOARD CitiPower Plant Eastex Total
-------- --------- ------------ ------ -----
(in millions)
2003 Revenue $- $- $14 $12 $26
2002 Revenue - (2) 18 22 38
2003 Earnings
(Loss) After Tax $- $- $- $- $-
2002 Earnings
(Loss) After Tax 46 (8) 4 (3) 39
For the nine months ended September 30, 2003 and 2002:
Pushan Power
SEEBOARD CitiPower Plant Eastex Total
-------- --------- ------------ ------ -----
(in millions)
2003 Revenue $- $- $41 $58 $99
2002 Revenue 694 204 44 50 992
2003 Earnings
(Loss) After Tax $- $- $(1) $(15) $(16)
2002 Earnings
(Loss) After Tax 82 (116) 7 (8) (35)
ASSETS HELD FOR SALE
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), during 2002, we recorded an estimated
loss on disposal of assets held for sale. The following provides an
update of those assets still held for sale.
Pushan Power Plant
We currently anticipate that negotiations to sell our interest in the
Pushan Power Plant (Pushan) in Nanyang, China to one of the minority
interest partners will be completed by the second quarter of 2004. This
anticipated closing date is later than originally expected due to
several unusual circumstances including the SARS outbreak and
governmental and regulatory delays. Results of operations of Pushan have
been reclassified as Discontinued Operations in accordance with SFAS
144. The assets and liabilities of Pushan have been reclassified on our
Consolidated Balance Sheets as Assets Held for Sale and Liabilities Held
for Sale. See the tables at the end of this section for more detailed
information.
Excess Equipment
In November 2002, as a result of a cancelled development project, we
obtained title to a surplus gas turbine generator. We anticipate the
sale of the turbine before the end of 2003. The Other Assets have been
reclassified on our Consolidated Balance Sheets as Assets Held for Sale.
See the tables at the end of this section for more detailed information.
Excess Real Estate
In the fourth quarter of 2002, we began to market an under-utilized
office building in Dallas, TX obtained through the merger with CSW. We
currently anticipate the sale of the facility to be completed by the end
of 2003. The property asset has been reclassified on our Consolidated
Balance Sheets as Assets Held for Sale. See the tables at the end of
this section for more detailed information.
The assets and liabilities of the entities held for sale at September
30, 2003 and December 31, 2002 are as follows:
Pushan
Power Excess Excess
Plant Real Estate Equipment Total
------ ----------- --------- -----
September 30, 2003 (in millions)
------------------
Assets:
Current Assets $20 $- $- $20
Property, Plant and
Equipment, Net 144 18 - 162
Other Assets - - 12 12
----- ---- ---- -----
Total Assets Held
for Sale $164 $18 $12 $194
===== ==== ==== =====
Liabilities:
Current Liabilities $26 $- $- $26
Long-term Debt 20 - - 20
Other Liabilities 52 - - 52
----- ---- ---- -----
Total Liabilities
Held for Sale $98 $- $- $98
===== ==== ==== =====
Pushan Excess Water
Power Newgulf Nordic Real Excess Heater Tele-
Plant Facility Trading Estate Equipment Program communications Total
------ -------- ------- ------ --------- ------- -------------- -----
December 31, 2002 (in millions)
-----------------
Assets:
Current Assets $19 $- $35 $- $- $1 $- $55
Property, Plant and
Equipment, Net 132 6 - 18 - 38 6 200
Other Assets - - 10 - 12 - - 22
----- --- ---- ---- ---- ---- --- -----
Total Assets
Held for Sale $151 $6 $45 $18 $12 $39 $6 $277
===== === ==== ==== ==== ==== === =====
Liabilities:
Current Liabilities $28 $- $48 $- $- $- $- $76
Long-term Debt 25 - - - - - - 25
Other Liabilities 26 - 3 - - - - 29
----- --- ---- ---- ---- ---- --- -----
Total Liabilities
Held for Sale $79 $- $51 $- $- $- $- $130
===== === ==== ==== ==== ==== === =====
IMPAIRMENTS
During the third quarter of 2003, we initiated an effort to sell four
domestic Independent Power Producer (IPP) investments accounted for
under the equity method. Based on studies of recent market conditions
and assumptions, it was determined that an other than temporary
impairment existed on two of the equity investments. The impairment was
the result of the measurement of fair value that was triggered by our
recent decision to sell the assets. A $70.0 million pre-tax ($45.5
million net of tax) charge was recorded in September 2003 as a result of
the other than temporary impairment of the equity interest under APB 18.
This loss of investment value is included in Investment Value and Other
Impairment Losses on our Consolidated Statements of Operations. These
equity investments are included in our "Investments - Other" business
segment.
9. BUSINESS SEGMENTS
-----------------
Our segments and their related business activities are as follows:
Utility Operations
o Domestic generation of electricity for sale to retail and wholesale
customers
o Domestic electricity transmission and distribution
o Parent company, which includes corporate related expenditures,
interest income and interest expense
Investments - Gas Operations
o Gas pipeline and storage services
Investments - UK Operations
o International generation of electricity for sale to wholesale
customers
Investments - Other
o Coal mining, bulk commodity barging operations and other energy
supply businesses
The tables below present segment information for the nine months ended
September 30, 2003 and 2002 and the three months ended September 30,
2003 and 2002. These amounts include certain estimates and allocations
where necessary.
Investments
----------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
---------- ---------- ---------- ----- ----------- ------------
Nine Months Ended September 30, 2003 (in millions)
Revenues from:
External Customers $8,512 $2,791 $116 $439 $ - $11,858
Other Operating Segments 15 255 - 74 (344) -
Discontinued Operations - - - (16) - (16)
Cumulative Effect of
Accounting Changes,
net of tax 237 (22) (22) - - 193
Net Income (Loss) 1,123 (81) (110) (60) - 872
Total Assets 29,262 3,062 1,847 1,714 194 (a) 36,079
Gross Property Additions 916 10 9 6 - 941
Investments
----------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
---------- ---------- ---------- ----- ----------- ------------
Nine Months Ended September 30, 2002 (in millions)
Revenues from:
External Customers $7,858 $1,803 $187 $536 $ - $10,384
Other Operating Segments - 192 - 120 (312) -
Discontinued Operations - - - (35) - (35)
Cumulative Effect of
Accounting Changes,
net of tax - - - (350) - (350)
Net Income (Loss) 846 (75) 6 (459) - 318
Total Assets 26,700 4,857 1,644 2,350 814(a) 36,365
Gross Property Additions 942 33 31 131 - 1,137
Investments
----------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
---------- ---------- ---------- ----- ----------- ------------
Three Months Ended September 30, 2003 (in millions)
Revenues from:
External Customers $3,111 $860 $4 $134 $- $4,109
Other Operating Segments 15 155 - 46 (216) -
Discontinued Operations - - - - - -
Cumulative Effect of
Accounting Changes,
net of tax - - - - - -
Net Income (Loss) 372 (20) (51) (44) - 257
Total Assets 29,262 3,062 1,847 1,714 194(a) 36,079
Gross Property Additions 289 - - 3 - 292
Investments
----------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
---------- ---------- ---------- ----- ----------- ------------
Three Months Ended September 30, 2002 (in millions)
Revenues from:
External Customers $2,940 $700 $53 $118 $- $3,811
Other Operating Segments - 58 - 42 (100) -
Discontinued Operations - - - 39 - 39
Cumulative Effect of
Accounting Changes,
net of tax - - - - - -
Net Income (Loss) 405 5 (5) 20 - 425
Total Assets 26,700 4,857 1,644 2,350 814(a) 36,365
Gross Property Additions 311 17 11 14 - 353
(a) Reconciling adjustments for Total Assets include Assets Held for
Sale and/or Assets of Discontinued Operations.
10. LEASES
------
OPCo has entered into an agreement with JMG Funding LLP (JMG), an
unrelated special purpose entity. JMG has a capital structure of which
3% is equity from investors with no relationship to AEP or any of its
subsidiaries and 97% is debt from commercial paper, pollution control
bonds and other bonds. JMG was formed to design, construct and lease the
Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
and leases it to OPCo. The lease is accounted for as an operating lease.
Payments under the operating lease are based on JMG's cost of financing
(both debt and equity) and include an amortization component plus the
cost of administration. OPCo and AEP do not have an ownership interest
in JMG and do not guarantee JMG's debt.
On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46.
Upon consolidation, OPCo recorded the assets and liabilities of JMG
($469.6 million). OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's
operating lease expenses. There was no cumulative effect of an
accounting change recorded as a result of our requirement to consolidate
JMG, and there was no change in net income due to the consolidation of
JMG.
At any time during the lease, OPCo has the option to purchase the Gavin
Scrubber for the greater of its fair market value or adjusted
acquisition cost (equal to the unamortized debt and equity of JMG) or
sell the Gavin Scrubber. The initial 15-year lease term is
non-cancelable. At the end of the initial term, OPCo can renew the
lease, purchase the Gavin Scrubber (terms previously mentioned), or sell
the Gavin Scrubber. In case of a sale at less than the adjusted
acquisition cost, OPCo must pay the difference to JMG.
In June 2003, we entered into an agreement with an unrelated,
unconsolidated leasing company to lease 875 coal-transporting aluminum
railcars. The lease has an initial term of five years and may be renewed
for up to three additional five-year terms, for a maximum of twenty
years. We intend to renew the lease for the full twenty years. At the
end of each lease term, we may (a) renew for another five-year term, not
to exceed a total of twenty years, (b) purchase the railcars for the
purchase price amount specified in the lease, projected at the lease
inception to be the then fair market value, or (c) return the railcars
and arrange a third party sale (return-and-sale option). The lease is
accounted for as an operating lease with the future payment obligations
included in the annual lease footnote.
This operating lease agreement allows us to avoid a large initial
capital expenditure, and to spread our railcar cost evenly over the
expected twenty-year usage period. In addition, the lease allows us to
take the income tax benefits otherwise associated with ownership.
Under the lease agreement, the lessor is guaranteed that the sale
proceeds under the return-and-sale option discussed above will equal at
least a lessee obligation amount specified in the lease, which declines
over time from approximately 86% to 77% of the projected fair market
value of the equipment. At September 30, 2003, the maximum potential
loss was approximately $31.5 million ($20.5 million net of tax) assuming
the fair market value of the equipment is zero at the end of the current
lease term. The railcars are subleased for one year to an unaffiliated
company under an operating lease. The sublessee may renew the lease for
up to four additional one-year terms.
11. MINORITY INTEREST IN FINANCE SUBSIDIARY
---------------------------------------
Due to the application of FIN 46, we deconsolidated Caddis Partners, LLC
(Caddis), which included amounts previously reported as Minority
Interest in Finance Subsidiary ($759 million at December 31, 2002 and
$533 million at June 30, 2003). As a result, a note payable to Caddis is
reported as Notes Payable to Caddis, a component of Long-Term Debt ($527
million at September 30, 2003). Due to the prospective application of
FIN 46 we did not change the presentation of Minority Interest in
Finance Subsidiary in periods prior to July 1, 2003.
In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC
(SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned
consolidated subsidiary of AEP that was capitalized with the assets of
Houston Pipe Line Company and Louisiana Intrastate Gas Company (AEP
subsidiaries) and $321.4 million of AEP Energy Services Gas Holding
Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne)
preferred stock, that was convertible into AEP common stock at market
price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an
unconditional obligation to fund $83 million from SubOne for a managing
member interest and $750 million from Steelhead Investors LLC
(Steelhead) for a non-controlling preferred member interest. As managing
member, SubOne consolidated Caddis. Steelhead is an unconsolidated
special purpose entity and had an original capital structure of $750
million (currently approximately $525 million) of which 3% is equity
from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The $525 million invested in
Caddis by Steelhead was loaned to SubOne. The loan to SubOne is due
August 2006.
On May 9, 2003, SubOne borrowed $225 million from AEP and used the
proceeds to reduce the outstanding balance of the loan from Caddis,
which Caddis used to reduce the preferred interest held by Steelhead.
This payment eliminated the convertible preferred stock of AEP Gas
Holding and the stock price trigger.
The credit agreement between Caddis and SubOne contains covenants that
restrict certain incremental liens and indebtedness, asset sales,
investments, acquisitions, and distributions. The credit agreement also
contains covenants that impose minimum financial ratios. Non-performance
of these covenants may result in an event of default under the credit
agreement. Through September 30, 2003, SubOne has complied with the
covenants contained in the credit agreement. In addition, the
acceleration of AEP and certain subsidiaries' debt outstanding, in
excess of $50 million, is an event of default under the credit
agreement.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events, including a default in the payment of the
preferred return, Steelhead's rights include forcing a liquidation of
Caddis and acting as the liquidator. Liquidation of Caddis could
negatively impact AEP's liquidity.
Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are
separate and legally distinct from AEP.
SubOne has deposited $414 million in a cash reserve fund in order to
comply with certain covenants in the credit agreement. Pursuant to the
terms of the credit agreement, SubOne subsequently loaned these funds to
affiliates, and AEP guaranteed the repayment obligations of these
affiliates. These loans must be repaid in the event AEP's credit ratings
fall below investment grade.
12. FINANCING AND RELATED ACTIVITIES
--------------------------------
Long-term debt and other securities issuances and retirements during the
first nine months of 2003 were:
Principal Interest Due
Company Type of Debt Amount Rate Date
------- ------------ --------- -------- ----
(in millions) (%)
Issuances:
AEP Senior Unsecured Notes $500 5.375 2010
AEP Senior Unsecured Notes 300 5.25 2015
AEP Other Debt 2 Variable 2005
APCo Senior Unsecured Notes 200 3.60 2008
APCo Senior Unsecured Notes 200 5.95 2033
APCo Installment Purchase
Contracts 100 5.50 2022
CSPCo Senior Unsecured Notes 250 5.50 2013
CSPCo Senior Unsecured Notes 250 6.60 2033
KPCo Senior Unsecured Notes 75 5.625 2032
OPCo Senior Unsecured Notes 250 5.50 2013
OPCo Senior Unsecured Notes 250 6.60 2033
OPCo Senior Unsecured Notes 225 4.85 2014
OPCo Senior Unsecured Notes 225 6.375 2033
PSO Senior Unsecured Notes 150 4.85 2010
SWEPCo Senior Unsecured Notes 100 5.375 2015
SWEPCo Secured Note of Subsidiary 44 4.47 2011
TCC Senior Unsecured Notes 150 3.00 2005
TCC Senior Unsecured Notes 100 Variable 2005
TCC Senior Unsecured Notes 275 5.50 2013
TCC Senior Unsecured Notes 275 6.65 2033
TNC Senior Unsecured Notes 225 5.50 2013
Principal Interest Due
Company Type of Debt Amount Rate Date
------- ------------ --------- -------- ----
(in millions) (%)
Retirements:
AEP Bank Facility $1,300 Variable 2003
AEP Senior Unsecured Notes 49 6.125 2006
AEP Senior Unsecured Notes 250 5.50 2003
AEP Other Debt 9 Variable 2005
APCo First Mortgage Bonds 70 8.50 2022
APCo First Mortgage Bonds 30 7.80 2023
APCo First Mortgage Bonds 20 7.15 2023
APCo Installment Purchase
Contracts 10 7.875 2013
APCo Installment Purchase
Contracts 40 6.85 2022
APCo Installment Purchase
Contracts 50 6.60 2022
APCo Senior Unsecured Notes 100 7.20 2038
APCo Senior Unsecured Notes 100 7.30 2038
APCo Senior Unsecured Notes 125 Variable 2003
CSPCo First Mortgage Bonds 2 8.70 2022
CSPCo First Mortgage Bonds 15 8.55 2022
CSPCo First Mortgage Bonds 14 8.40 2022
CSPCo First Mortgage Bonds 13 8.40 2022
CSPCo First Mortgage Bonds 13 6.80 2003
CSPCo First Mortgage Bonds 26 6.55 2004
CSPCo First Mortgage Bonds 26 6.75 2004
CSPCo First Mortgage Bonds 40 7.90 2023
CSPCo First Mortgage Bonds 33 7.75 2023
CSPCo First Mortgage Bonds 25 6.60 2003
I&M First Mortgage Bonds 75 8.50 2022
I&M First Mortgage Bonds 15 7.35 2023
I&M Junior Debentures 40 8.00 2026
I&M Junior Debentures 125 7.60 2038
KPCo Junior Debentures 40 8.72 2025
OPCo First Mortgage Bonds 30 6.75 2003
PSO First Mortgage Bonds 35 6.25 2003
PSO First Mortgage Bonds 65 7.25 2003
SWEPCo First Mortgage Bonds 55 6.625 2003
SWEPCo Secured Note of Subsidiary 2 4.47 2011
SWEPCo Notes Payable 1 Variable 2008
TCC First Mortgage Bonds 18 7.50 2023
TCC First Mortgage Bonds 16 6.875 2003
TCC Securitization Bonds 51 3.54 2005
Non-Registrant:
AEP Subsidiary Notes Payable 7 6.225 2017
AEP Subsidiary Revolving Credit
Agreement 306 Variable 2003
AEP Subsidiary Senior Unsecured Notes 17 6.50 2003
AEP Subsidiary Other Debt 6 Variable 2007
In addition to the transactions reported in the table above, the
following table lists intercompany issuances and retirements of debt due
to AEP:
Principal Interest Due
Company Type of Debt Amount Rate Date
------- ------------ --------- -------- ----
(in millions) (%)
Issuance:
Non-Registrant
AEP Subsidiary Notes Payable $225 5.57 2010
Retirements:
CSPCo Notes Payable $160 6.501 2006
KPCo Notes Payable 15 4.336 2003
OPCo Notes Payable 240 6.501 2006
OPCo Notes Payable 60 4.336 2003
Non-Registrant:
AEP Subsidiaries Notes Payable 105 4.336 2003
AEP Subsidiary Notes Payable 12 6.501 2006
Other Matters
In May 2003, a third party exercised its option to call our $250 million
of 5.50% putable callable notes, issued in May 2001, for purchase and
remarketing. On May 15, 2003, 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.
AEP Credit extended its sale of receivables agreement from its May 28,
2003 expiration to July 25, 2003, when the agreement was renewed for an
additional 364 days. The new sale of receivables agreement, which
expires on July 23, 2004, provides commitments of $600 million to
purchase receivables from AEP Credit. At September 30, 2003, $529
million of commitments to purchase accounts receivable were outstanding
under the receivables agreement. All receivables sold represent
affiliate receivables. AEP Credit maintains a retained interest in the
receivables sold and this interest is pledged as collateral for the
collection of receivables sold. The fair value of the retained interest
is based on book value due to the short-term nature of the accounts
receivable less an allowance for anticipated uncollectible accounts.
In September 2003, AEP closed on a $200 million revolving loan and
letter of credit facility. The facility is available for the issuance of
letters of credit and for general corporate purposes. The facility will
expire in September 2006.
Common Stock
In March 2003, we issued 56 million shares of common stock at $20.95 per
share through an equity offering and received net proceeds of $1,141
million (net of issuance costs of $36 million). Proceeds from the sale
of common stock were used to pay down both short-term and long-term debt
with the balance being held in cash.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
AEGCo is engaged in the generation and wholesale sale of electric power to two
affiliates under long-term agreements. Operating revenues are derived from the
sale of Rockport Plant energy and capacity to two affiliated companies pursuant
to FERC approved long-term unit power agreements. The unit power agreements
provide for a FERC approved rate of return on common equity (12.16% annually), a
return on other capital (net of temporary cash investments) and recovery of
costs including operation and maintenance, fuel and taxes.
Results of Operations
Net Income increased $74 thousand during the third quarter of 2003 compared with
the third quarter of 2002 and increased $27 thousand in the nine-month period
ended September 30, 2003 compared with the nine-month period ended September 30,
2002. The fluctuations in Net Income are a result of terms in the unit power
agreements which limit recovery of return on capital related to operating and
in-service ratios of the Rockport Plant calculated and adjusted monthly.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income increased $373 thousand for the third quarter primarily due to
the following:
o Operating Revenue increased as a result of increased recoverable
expenses, primarily Other Operation and Maintenance, in accordance
with the unit power agreements.
The increase in Operating Income was partially offset by the following:
o Fuel for Electric Generation expense increased primarily due to an
increase in the average cost of coal.
o Other Operation and Maintenance increased in the current quarter due
to a planned maintenance outage in September 2003.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income increased $467 thousand year-to-date primarily due to the
following:
o Operating Revenue increased as a result of increased recoverable
expenses, primarily fuel, as net generation increased 15%
year-to-date.
o Other Operation and Maintenance decreased year-to-date due to
higher costs incurred for planned maintenance outages in the first
quarter of 2002.
o The decrease in Taxes Other Than Income Taxes year-to-date
reflects a decline in the accrual of Indiana's real and personal
property taxes for the Rockport Plant, reflecting a favorable
change in the tax law effective March 2002.
The increase in Operating Income was partially offset by the following:
o Fuel for Electric Generation expense increased primarily due to
increased generation and an increase in the average cost of coal.
o Income Taxes attributable to operations increased due to an
increase in pre-tax operating book income.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $59,008 $55,988 $179,004 $159,219
-------- -------- --------- ---------
OPERATING EXPENSES
- --------------------------------------------------------
Fuel for Electric Generation 27,514 26,702 87,148 65,737
Rent - Rockport Plant Unit 2 17,071 17,071 51,212 51,212
Other Operation 2,691 2,023 7,683 9,259
Maintenance 2,461 1,484 6,399 6,838
Depreciation 5,695 5,643 16,981 16,918
Taxes Other Than Income Taxes 1,085 1,150 2,480 3,110
Income Taxes 682 479 1,927 1,438
-------- -------- --------- ---------
TOTAL 57,199 54,552 173,830 154,512
-------- -------- --------- ---------
OPERATING INCOME 1,809 1,436 5,174 4,707
Nonoperating Income 3 74 24 108
Nonoperating Expenses (Credits) 44 (8) 286 98
Nonoperating Income Tax Credits 878 886 2,617 2,541
Interest Charges 625 457 1,944 1,700
-------- -------- --------- ---------
NET INCOME $2,021 $1,947 $5,585 $5,558
======== ======== ========= =========
STATEMENTS OF RETAINED EARNINGS
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $19,384 $15,272 $18,163 $13,761
Net Income 2,021 1,947 5,585 5,558
Cash Dividends Declared 1,172 1,050 3,515 3,150
-------- -------- --------- ---------
BALANCE AT END OF PERIOD $20,233 $16,169 $20,233 $16,169
======== ======== ========= =========
The common stock of AEGCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ------------------------------------------------------------------------------
Production $645,047 $637,095
General 4,278 4,728
Construction Work in Progress 12,928 10,390
--------- ---------
TOTAL 662,253 652,213
Accumulated Depreciation 374,740 358,174
--------- ---------
TOTAL - NET 287,513 294,039
--------- ---------
Other Property and Investments 119 119
CURRENT ASSETS
- ------------------------------------------------------------------------------
Accounts Receivable - Affiliated Companies 20,481 18,454
Fuel 14,829 20,260
Materials and Supplies 5,179 4,913
Prepayments 24 -
--------- ---------
TOTAL 40,513 43,627
--------- ---------
Regulatory Assets 5,674 4,970
Deferred Charges 6,119 6,974
TOTAL ASSETS $339,938 $349,729
========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - Par Value $1 per share:
Authorized and Outstanding - 1,000 Shares $1,000 $1,000
Paid-in Capital 23,434 23,434
Retained Earnings 20,233 18,163
--------- ---------
Total Common Shareholder's Equity 44,667 42,597
Long-term Debt 44,809 44,802
--------- ---------
TOTAL 89,476 87,399
--------- ---------
Other Noncurrent Liabilities 1,305 301
CURRENT LIABILITIES
- ------------------------------------------------------------------------------
Advances from Affiliates 6,879 28,034
Accounts Payable:
General - 26
Affiliated Companies 14,176 15,907
Taxes Accrued 4,360 2,327
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 603 1,111
--------- ---------
TOTAL 49,445 52,368
--------- ---------
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 106,868 111,046
REGULATORY LIABILITIES
- ------------------------------------------------------------------------------
Deferred Investment Tax Credit 50,440 52,943
Amounts Due to Customers for Income Taxes 15,191 16,670
--------- ---------
TOTAL 65,631 69,613
--------- ---------
Deferred Income Taxes 27,213 29,002
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $339,938 $349,729
========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------------------------------
Net Income $5,585 $5,558
Adjustments to Reconcile Net Income to Net Cash Flows From
Operating Activities:
Depreciation 16,981 16,918
Deferred Income Taxes (3,268) (3,328)
Deferred Investment Tax Credits (2,503) (2,504)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (4,178) (4,178)
Changes in Certain Assets and Liabilities:
Accounts Receivable (2,027) (11,370)
Fuel, Materials and Supplies 5,165 1,741
Accounts Payable (1,757) 31,076
Taxes Accrued 2,033 4,225
Deferred Property Taxes (795) (881)
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 1,383 243
Change in Other Liabilities (558) (644)
-------- --------
Net Cash Flows From Operating Activities 34,525 55,320
-------- --------
INVESTING ACTIVITIES - Construction Expenditures (9,855) (6,956)
-------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------------------------------
Change in Advances from Affiliates (21,155) (46,197)
Dividends Paid (3,515) (3,150)
-------- --------
Net Cash Flows Used For Financing Activities (24,670) (49,347)
-------- --------
Net Decrease in Cash and Cash Equivalents - (983)
Cash and Cash Equivalents at Beginning of Period - 983
-------- --------
Cash and Cash Equivalents at End of Period $- $-
======== ========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $2,200,000 and $1,983,000
and for income taxes was $5,939,000 and $2,442,000 in 2003 and 2002,
respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income decreased $27 million for the third quarter, but increased $43
million year-to-date. The decreased income for the quarter is due to decreased
margins on system sales, offset in part by the recognition of non-cash earnings
related to legislatively mandated capacity auctions and regulatory assets
established in Texas of $39 million net of tax. The increased income for the
year-to-date is associated with the recognition of non-cash earnings related to
the capacity auction true-up in Texas of $110 million net of tax, offset in part
by decreased margins on system sales.
Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs, effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.
In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who
assumed the obligations of the affiliated REP including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy CPL were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions and delivery charges
with Mutual Energy CPL are classified as Electric Generation, Transmission and
Distribution.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income decreased $34 million primarily due to:
o Decreased system sales, including those to REPs, of $75 million,
due mainly to decreased KWH sales and a decrease in the overall
average price per KWH.
o Decreased revenues from ERCOT for various services, including balancing
energy, of $45 million.
o The 2002 ICR adjustments that accounted for approximately $60
million of the decrease (See "ICR Explanation: in Note 6 in the
Annual Report, as updated by the Current Report on Form 8-K dated
May 14, 2003, for discussion of the ICR adjustments).
o Decreased delivery revenues of $25 million partially due to a 7%
decrease in cooling degree days.
o Decreased transmission revenues of $6 million.
o Increased fuel and purchased electricity on a combined basis of
$10 million. Fuel increased almost entirely due to increased per
unit fuel costs, which rose 54%, mostly due to natural gas prices.
Purchased power decreased in large part due to the 2002 ICR
adjustments of $51 million (see "ICR Explanation" in Note 6 in the
Annual Report, as updated by the Current Report on Form 8-K dated
May 14, 2003, for discussion of the ICR adjustments.) While purchased
KWH increased 38%, the average cost per unit decreased 16%.
o Increased Other Operation expense of $3 million due mainly to
accretion expense associated with the adoption of SFAS 143
(see Note 2).
o Increased maintenance expense of $1 million due mainly to unscheduled
repairs at the STP nuclear plant.
The decrease in Operating Income was partially offset by:
o Reliability Must Run (RMR) revenues from ERCOT of $66 million
which include both fuel recovery and a fixed cost component of $9
million (see "Texas Plants" in Note 13 in the Annual Report, as
updated by the Current Report on Form 8-K dated May 14, 2003, for
discussion of RMR facilities).
o Revenues associated with establishing regulatory assets in Texas
of $61 million for the third quarter 2003 (see "Texas Restructuring"
in Note 4).
o Increased revenues from risk management activities of $20 million.
o Decreased Depreciation and Amortization expense of $16 million due
mainly to the reversal of prior years' excess earnings accruals
under the Texas restructuring legislation due to a favorable
Appeals Court ruling (See Note 4), decreases resulting from ARO
(see Note 2), reduced depreciable plant due to the mothballing of
certain generating units in 2002 and changes resulting from
amortization of regulatory assets.
o Decreased Income Taxes of $26 million due mainly to decreases in
pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income increased $15 million primarily due to increased gains from
risk management activities partially offset by lower non-utility revenues
associated with energy related construction projects for third parties.
Nonoperating Expense decreased $7 million primarily due to lower non-utility
expenses associated with energy related construction projects for third parties.
Nonoperating Income Tax Expense (Credit) increased $8 million due to higher
pre-tax nonoperating book income.
Interest Charges increased $7 million primarily due to increased average levels
of debt outstanding during the quarter.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income increased $35 million primarily due to:
o Revenues associated with establishing regulatory assets in Texas
of $169 million in 2003 (see "Texas Restructuring" in Note 4).
o Reliability Must Run (RMR) revenues from ERCOT of $188 million
which include both fuel recovery and a fixed cost component of $26
million (see "Texas Plants" in Note 13 in the Annual Report, as
updated by the Current Report on Form 8-K dated May 14, 2003, for
discussion of RMR facilities).
o Increased revenues of $33 million resulting from risk management
activities.
o Decreased Depreciation and Amortization expense of $23 million due
mainly to decreases resulting from ARO (see Note 2), reduced
depreciable plant due to the mothballing of certain generating
units in 2002 and changes resulting from amortization of
regulatory assets.
o Reduced Taxes Other Than Income Taxes of $9 million resulting from
lower property taxes and state gross receipts taxes stemming from
deregulation in Texas.
The increase in Operating Income was partially offset by:
o Decreased system sales, including those to REPs, of $34 million due
mainly to both lower KWH sales and a decrease in the overall average
price per KWH.
o Revenues from ERCOT for various services, including balancing energy,
which declined $39 million.
o The 2002 ICR adjustments that accounted for approximately $60
million of the decrease (See "ICR Explanation" in Note 6 in the
Annual Report, as updated by the Current Report on Form 8-K dated
May 14, 2003, for discussion of the ICR adjustments).
o Decreased delivery revenues of $41 million driven by a 10%
decrease in cooling degree days and a slight decrease in heating
degree days.
o Increased provisions for rate refunds of $39 million due mainly to
Texas fuel issues (see "TCC Fuel Reconciliation" in Note 3).
o Net increases in fuel and purchased electricity on a combined
basis of $175 million to replace portions of the energy from the
non-RMR mothballed plants and the unscheduled forced outage at the
STP nuclear unit (See "Significant Factors" below). KWH purchased
increased 108% while the total cost increased 90%. Although the
KWH generated decreased, fuel costs increased due to 43% higher
per unit costs attributable mostly to natural gas. This increase
was partially offset by the effect of the 2002 ICR adjustments.
o Increased Maintenance expense of $14 million due mainly to the STP
Unit 2 forced outage in the first quarter and the STP Unit 1
scheduled refueling outage and forced outage in the second and
third quarters of 2003.
o Increased Income Taxes of $14 million due mainly to increases in
pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income increased $19 million primarily due to increased gains from
risk management activities partially offset by lower non-utility revenues
associated with energy related construction projects for third parties.
Nonoperating Expense decreased $9 million primarily due to lower non-utility
expenses associated with energy related construction projects for third parties.
Nonoperating Income Tax Expense (Credit) increased $9 million due to higher
pre-tax nonoperating book income.
Interest Charges increased $11 million primarily due to the replacement of lower
cost short-term floating rate debt with longer-term higher cost fixed rate debt.
Cumulative Effect of Accounting Change
This amount represents the one-time after-tax effect of the application of EITF
02-3 (see Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Our current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB A
Senior Unsecured Debt Baa2 BBB A-
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of TCC's rating for unsecured debt from Baa1 to Baa2 and secured debt from A3 to
Baa1. The completion of this review was a culmination of ratings action started
during 2002. With the completion of the reviews, Moody's has placed AEP and its
rated subsidiaries on stable outlook. In March 2003, S&P lowered AEP and our
senior unsecured debt and first mortgage bonds ratings from BBB+ to BBB.
Cash Flow
Cash flows for the nine months ended September 30, 2003 and 2002 were as
follows:
2003 2002
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $85,420 $10,909
Cash flow from (used for):
Operating activities 231,397 33,502
Investing activities (94,818) (97,952)
Financing activities (179,247) 110,179
--------- --------
Net increase (decrease) in cash and cash equivalents (42,668) 45,729
--------- --------
Cash and cash equivalents at end of period $42,752 $56,638
========= ========
Operating Activities
Cash flow from operating activities increased $198 million from the prior year
primarily due to a $43 million increase in net income as explained above and
accounts receivables changes related to reduced energy sales due primarily to
REP related sales receivables, partially offset by the non-cash Texas wholesale
capacity auction revenues recorded in 2003.
Investing Activities
Construction expenditures in 2003 versus 2002 decreased by $3 million.
Construction expenditures of $95 million in the current year were focused on
improved service reliability projects for transmission and distribution systems
costing $68 million.
Financing Activities
We obtained the additional funds needed for investing and financing activities
through new borrowings of $800 million in 2003 and $997 million in 2002. Current
year debt proceeds replaced short and long-term debt. Prior year debt proceeds
replaced long-term debt and retired common stock.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------------ --------- -------- ----
(in millions) (%)
Senior Unsecured Notes $150 3.00 2005
Senior Unsecured Notes 100 Variable 2005
Senior Unsecured Notes 275 5.50 2013
Senior Unsecured Notes 275 6.65 2033
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
--------- -------- ----
(in millions) (%)
First Mortgage Bonds $16 6.875 2003
First Mortgage Bonds 18 7.50 2023
Securitization Bonds 51 3.54 2005
Significant Factors
- -------------------
Possible Divestitures
In June 2003, we began actively seeking buyers for 4,497 megawatts of
unregulated generation capacity in Texas. The value received from this
disposition will be used to calculate our strande cost in Texas (see Note 4).
We expect to receive final bids in the fourth quarter of 2003.
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.
Nuclear Plant Outage
In April 2003, engineers at STP, during inspections conducted regularly as part
of scheduled 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.
Industry Restructuring
As discussed in the 2002 Annual Report (as updated by the Current Report on Form
8-K dated May 14, 2003), on January 1, 2002, customer choice began in the ERCOT
area of Texas. 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.
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. We have 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 our methodology. We 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, our 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 we have 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 3 and 4 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.
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $5,414
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (2,671)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission 187
Changes in Fair Value of Risk Management
Contracts (d) 16,097
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
--------
Total MTM Risk Management Contract Net Assets 19,027
Net Non-Trading Related Derivative Contracts 464
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $19,491
========
(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,
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
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
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 our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $410 $4,572 $2,020 $1,771 $419 $- $9,192
Prices Based on Models and Other Valuation
Methods (b) 688 1,662 1,054 1,275 1,406 3,750 9,835
------- ------- ------- ------- ------- ------- --------
Total $1,098 $6,234 $3,074 $3,046 $1,825 $3,750 $19,027
======= ======= ======= ======= ======= ======= ========
(a)"Prices Provided by Other External Sources - OTC Broker Quotes" reflects
information obtained from over-the-counter brokers, industry services, or
multiple-party on-line platforms.
(b)"Prices Based on Models and Other Valuation Methods" if there is
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 varies by
market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power
--------
(in thousands)
Accumulated OCI, December 31, 2002 $(36)
Changes in Fair Value (a) 200
Reclassifications from OCI to Net
Income (b) 137
-----
Accumulated OCI Derivative Gain September
30, 2003 $301
=====
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $525 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$278 $788 $363 $78 $115 $353 $126 $26
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- -------------------------------------------------------------
Electric Generation, Transmission and Distribution $443,578 $111,051 $1,264,757 $306,238
Sales to AEP Affiliates 41,551 435,209 131,176 879,323
--------- --------- ----------- ----------
TOTAL 485,129 546,260 1,395,933 1,185,561
--------- --------- ----------- ----------
OPERATING EXPENSES
- -------------------------------------------------------------
Fuel for Electric Generation 24,475 21,081 73,244 70,808
Fuel from Affiliates for Electric Generation 72,776 42,576 155,976 137,133
Purchased Electricity for Resale 116,562 151,012 305,338 160,996
Purchased Electricity from AEP Affiliates 273 (10,433) 19,045 10,058
Other Operation 74,192 71,023 213,884 208,984
Maintenance 16,657 15,239 54,567 40,980
Depreciation and Amortization 46,151 62,242 142,084 165,012
Taxes Other Than Income Taxes 24,747 24,774 67,509 76,170
Income Taxes 24,794 50,542 91,171 77,452
--------- --------- ----------- ----------
TOTAL 400,627 428,056 1,122,818 947,593
--------- --------- ----------- ----------
OPERATING INCOME 84,502 118,204 273,115 237,968
Nonoperating Income 25,006 10,234 43,069 24,237
Nonoperating Expenses 3,647 10,184 14,479 23,049
Nonoperating Income Tax Expense (Credit) 6,319 (1,522) 7,117 (2,037)
Interest Charges 33,321 26,393 100,343 89,830
--------- --------- ----------- ----------
Income Before Cumulative Effect of Accounting Change 66,221 93,383 194,245 151,363
Cumulative Effect of Accounting Change (Net of Tax) - - 122 -
--------- --------- ----------- ----------
NET INCOME 66,221 93,383 194,367 151,363
Gain on Reacquired Preferred Stock - 4 - 4
Preferred Stock Dividend Requirements 60 60 181 181
--------- --------- ----------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $66,161 $ 93,327 $194,186 $151,186
========= ========= =========== ==========
The common stock of TCC is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
JANUARY 1, 2002 $168,888 $405,015 $826,197 $1,400,100
Redemption of Common Stock (113,596) (272,409) (386,005)
Common Stock Dividends (115,505) (115,505)
Preferred Stock Dividends (181) (181)
Capital Stock Gains 4 4
-----------
TOTAL 898,413
-----------
COMPREHENSIVE INCOME
- -------------------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges $58 58
NET INCOME 151,363 151,363
TOTAL COMPREHENSIVE INCOME 151,421
--------- --------- ----------- --------- -----------
SEPTEMBER 30, 2002 $55,292 $132,606 $861,878 $58 $1,049,834
========= ========= =========== ========= ===========
JANUARY 1, 2003 $55,292 $132,606 $986,396 $(73,160) $1,101,134
Common Stock Dividends (90,601) (90,601)
Preferred Stock Dividends (181) (181)
-----------
TOTAL 1,010,352
COMPREHENSIVE INCOME
- -------------------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 337 337
NET INCOME 194,367 194,367
-----------
TOTAL COMPREHENSIVE INCOME 194,704
--------- --------- ----------- --------- -----------
SEPTEMBER 30, 2003 $55,292 $132,606 $1,089,981 $(72,823) $1,205,056
========= ========= =========== ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------------------------
Production $3,001,939 $2,903,942
Transmission 776,256 698,964
Distribution 1,365,327 1,296,731
General 263,567 258,386
Construction Work in Progress 59,385 200,947
Nuclear Fuel 34,042 34,942
----------- -----------
TOTAL 5,500,516 5,393,912
Accumulated Depreciation and Amortization 2,151,475 2,173,668
----------- -----------
TOTAL - NET 3,349,041 3,220,244
----------- -----------
Other Property and Investments 8,598 3,977
Securitized Transition Assets 703,293 734,591
Long-term Risk Management Assets 16,823 4,392
CURRENT ASSETS
- -------------------------------------------------------------
Cash and Cash Equivalents 42,752 85,420
Advances to Affiliates 26,327 -
Accounts Receivable:
General 169,304 113,543
Affiliated Companies 110,360 121,324
Allowance for Uncollectible Accounts (248) (346)
Fuel Inventory 18,400 32,563
Materials and Supplies 48,696 51,593
Accrued Utility Revenues 34,757 27,150
Risk Management Assets 14,007 22,493
Prepayments and Other Current Assets 4,682 2,133
----------- -----------
TOTAL 469,037 455,873
----------- -----------
Regulatory Assets 659,427 458,552
Regulatory Assets Designated for or Subject to Securitization 320,713 336,444
Nuclear Decommissioning Trust Fund 114,930 98,474
Deferred Charges 66,962 43,891
TOTAL ASSETS $5,708,824 $5,356,438
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- -------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares $55,292 $55,292
Paid-in Capital 132,606 132,606
Accumulated Other Comprehensive Income (Loss) (72,823) (73,160)
Retained Earnings 1,089,981 986,396
----------- -----------
Total Common Shareholder's Equity 1,205,056 1,101,134
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,940 5,942
CPL - Obligated Mandatorily Redeemable Preferred Securities of
Subsidiary Trust Holding Solely Junior Subordinated Debentures of TCC - 136,250
Long-term Debt 2,081,274 1,209,434
----------- -----------
TOTAL 3,292,270 2,452,760
----------- -----------
Other Noncurrent Liabilities 326,943 74,572
CURRENT LIABILITIES
- -------------------------------------------------------------
Short-term Debt - Affiliates - 650,000
Long-term Debt Due Within One Year 210,251 229,131
Advances from Affiliates - 126,711
Accounts Payable:
General 88,601 72,199
Affiliated Companies 91,655 36,242
Customer Deposits 1,411 666
Taxes Accrued 48,834 24,791
Interest Accrued 24,467 51,205
Risk Management Liabilities 6,030 19,811
Other 27,075 36,698
----------- -----------
TOTAL 498,324 1,247,454
----------- -----------
Deferred Income Taxes 1,281,787 1,261,252
Deferred Investment Tax Credits 113,781 117,686
Long-term Risk Management Liabilities 5,309 1,713
Regulatory Liabilities and Deferred Credits 190,410 201,001
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $5,708,824 $5,356,438
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- -------------------------------------------------------------
Net Income $194,367 $151,363
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 142,084 165,012
Deferred Income Taxes 36,386 (14,620)
Deferred Investment Tax Credits (3,905) (3,905)
Cumulative Effect of Accounting Change (122) -
Mark-to-Market of Risk Management Contracts (13,426) (4,613)
Texas Wholesale Clawback (169,000) -
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (44,895) (258,663)
Fuel, Materials and Supplies 17,060 (6,214)
Interest Accrued (26,738) 17,375
Accrued Utility Revenues (7,607) -
Accounts Payable 71,815 (16,306)
Taxes Accrued 24,043 61,198
Deferred Property Tax (10,050) (9,560)
Change in Other Assets 14,359 (61,836)
Change in Other Liabilities 7,026 14,271
--------- ---------
Net Cash Flows From Operating Activities 231,397 33,502
--------- ---------
INVESTING ACTIVITIES
- -------------------------------------------------------------
Construction Expenditures (95,425) (97,952)
Other 607 -
--------- ---------
Net Cash Flows Used For Investing Activities (94,818) (97,952)
--------- ---------
FINANCING ACTIVITIES
- -------------------------------------------------------------
Change in Short-term Debt-Affiliates (650,000) 200,000
Issuance of Long-term Debt 800,000 797,335
Retirement of Long-term Debt (85,427) (583,836)
Change in Advances to/from Affiliates, Net (153,038) 198,371
Retirement of Common Stock - (386,005)
Dividends Paid on Common Stock (90,601) (115,505)
Dividends Paid on Cumulative Preferred Stock (181) (181)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (179,247) 110,179
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (42,668) 45,729
Cash and Cash Equivalents at Beginning of Period 85,420 10,909
--------- ---------
Cash and Cash Equivalents at End of Period $42,752 $56,638
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $117,427,000 and
$63,005,000 and for income taxes was $42,901,000 and $44,322,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income increased $45 million year-to-date and $22 million for the third
quarter primarily due to a $22 million write- down of inactivated power plants
in 2002. Additionally, year-to-date net income was increased as a result of a
Cumulative Effect of Accounting Changes of $3 million (see Note 2).
Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.
In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who
assumed the obligations of the affiliated REP, including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy WTU were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions and delivery charges
with Mutual Energy WTU are classified as Electric Generation, Transmission and
Distribution.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income increased by $18 million primarily due to:
o Reliability Must Run (RMR) revenues from ERCOT of $17 million,
which include both fuel recovery and a fixed cost component of $3
million (see "Texas Plants" in Note 13 in the Annual Report, as
updated by the Current Report on Form 8-K dated May 14, 2003, for
discussion of RMR facilities).
o Increased revenues from risk management activities of $6 million.
o Decreased fuel and purchased electricity on a combined basis of
$26 million due mainly to decreased KWH both generated and
purchased because of reduced sales due partly to a 2% decline in
cooling degree-days, and the effect of the 2002 ICR adjustments of
$5 million (see "ICR Explanation" in Note 6 in the Annual Report
as updated by the Current Report on Form 8-K dated May 14, 2003,
for discussion of the ICR adjustments). KWH generation also
decreased due to the inactivation of several plants in late 2002,
offset in part by a 12% increase in per unit costs due to
increases in natural gas prices.
o Reduced Other Operation expenses of $35 million resulting from the 2002
write-down of inactivated power plants.
o Reduced Depreciation and Amortization of $4 million mainly from
adjustments to prior years' excess earnings accruals under the Texas
restructuring legislation due to a favorable Appeals Court ruling
(see Note 4) and reduced depreciable plant due to the inactivation of
several power plants in late 2002.
The increase in Operating Income was partially offset by:
o Decreased system sales, including those to REPs, of $25 million due
mainly to lower KWH
o Revenues from ERCOT for various services, including balancing energy,
which declined $3 million.
o The 2002 ICR adjustments that accounted for approximately $25 million
of the decrease in revenue (See "ICR Explanation" in Note 6 in the
Annual Report, as updated by the Current Report on Form 8-K dated May
14, 2003, for discussion of the ICR adjustments.)
o Decreased delivery revenues of $7 million due partly to the decline
in cooling degree-days.
o Reduced wholesale base revenues of $6 million due to the loss of
several large wholesale customers whose contracts were not renewed.
o Increased provisions for rate refunds of $3 million in 2003.
o Increased Income Tax Expense (Credit) of $11 million due to increases
in pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income increased $8 million primarily due to increases from risk
management activities and non-utility revenues associated with energy-related
construction projects for third parties.
Nonoperating Expense increased $2 million primarily due to higher non-utility
expenses associated with energy-related construction projects for third parties.
Nonoperating Income Tax Expense (Credit) increased $2 million due to higher
pre-tax nonoperating book income.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income increased by $34 million primarily due to:
o Reliability Must Run (RMR) revenues from ERCOT of $40 million
which include both fuel recovery and a fixed cost component of $10
million (see "Texas Plants" in Note 13 in the Annual Report, as
updated by the Current Report on Form 8-K dated May 14, 2003, for
discussion of RMR facilities).
o Increased revenues from risk management activities of $9 million.
o Revenues from ERCOT for various services, including balancing energy,
which increased $8 million.
o Reduced Other Operation expenses of $41 million due mainly to the
2002 write-down of inactivated power plants, along with slight
decreases in customer, production and administrative expenses.
o Reduced Depreciation and Amortization of $8 million mainly from
adjustments to prior years' excess earnings accruals under the
Texas restructuring legislation due to a favorable Appeals Court
ruling (See Note 4), and reduced depreciable plant due to the
inactivation of several power plants in late 2002.
o Reduced Taxes Other Than Income Taxes of $3 million resulting from
lower property taxes and state gross receipts taxes stemming from
deregulation in Texas.
The increase in Operating Income was partially offset by:
o The 2002 ICR adjustments that accounted for approximately $25
million of the decrease in revenues (See "ICR Explanation" in Note
6 in the Annual Report, as updated by the Current Report on Form
8-K dated May 14, 2003, for discussion of the ICR adjustments.)
o Decreased delivery revenues of $7 million, due partly to decreased
cooling and heating degree-days.
o Reduced wholesale base revenues of $13 million due to the loss of
several large wholesale customers whose contracts expired and
were not renewed.
o Increased provision for rate refunds of $12 million in 2003 (see "TNC
Fuel Reconciliation" in Note 3).
o Increased fuel and purchased electricity on a combined basis of $4
million. KWH generation decreased 32% partly due to decreased
cooling degree-days of 7% and heating degree-days of 1%, but the
per unit cost of fuel increased 9% due to increased natural gas
prices. KWH purchased declined 9%, but the average cost increased
9%, and the 2002 ICR adjustments served to decrease purchased
power.
o Increased Income Tax Expense (Credit) of $22 million due to increases
in pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income increased $34 million primarily due to increases from risk
management activities and non-utility revenues associated with energy-related
construction projects for third parties.
Nonoperating Expense increased $23 million primarily due to higher non-utility
expenses associated with energy-related construction projects for third parties.
Nonoperating Income Tax Expense (Credit) increased $3 million due to higher
pre-tax nonoperating book income.
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 (see Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Our current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt Baa1 BBB A-
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. TNC had its secured debt downgraded from A2 to
A3 and unsecured debt downgraded from A3 to Baa1. The completion of this review
was a culmination of ratings action started during 2002. In March 2003, S&P
lowered AEP and our senior unsecured debt and mortgage bonds ratings from BBB+
to BBB.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Senior Unsecured Notes $225 5.50 2013
Retirements
-----------
None
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effects.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $2,043
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (178)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission 20
Changes in Fair Value of Risk Management
Contracts (d) 4,518
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) 445
-------
Total MTM Risk Management Contract Net Assets 6,848
Net Non-Trading Related Derivative
Contracts 178
-------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $7,026
=======
(a)"(Gain) Loss from Contracts Realized/Settled During the Period"
include 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, 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
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
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 our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Provided by Other External Sources
- OTC Broker Quotes (a) $148 $1,646 $727 $637 $151 $- $3,309
Prices Based on Models and Other
Valuation Methods (b) 247 598 379 459 506 1,350 3,539
----- ------- ------- ------- ----- ------- -------
Total $395 $2,244 $1,106 $1,096 $657 $1,350 $6,848
===== ======= ======= ======= ===== ======= =======
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power
--------
(in thousands)
Accumulated OCI, December 31, 2002 $(15)
Changes in Fair Value (a) 77
Reclassifications from OCI to Net
Income (b) 53
-----
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $115
=====
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $201 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$106 $302 $139 $30 $48 $146 $52 $11
AEP TEXAS NORTH COMPANY
STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ------------------------------------------------------------
Electric Generation, Transmission and Distribution $104,104 $ 62,041 $320,733 $155,375
Sales to AEP Affiliates 10,351 90,626 46,790 205,370
--------- --------- --------- ---------
TOTAL 114,455 152,667 367,523 360,745
--------- --------- --------- ---------
OPERATING EXPENSES
- ------------------------------------------------------------
Fuel for Electric Generation 9,457 8,276 29,196 26,289
Fuel from Affiliates for Electric Generation 14,390 15,498 31,392 55,307
Purchased Electricity for Resale 22,933 39,087 74,434 53,015
Purchased Electricity from AEP Affiliates 2,486 12,552 38,280 34,761
Other Operation 23,394 58,273 66,378 107,350
Maintenance 4,552 5,389 14,705 16,795
Depreciation and Amortization 7,132 11,513 26,387 34,154
Taxes Other Than Income Taxes 5,281 5,718 14,746 17,545
Income Tax Expense (Credit) 7,411 (3,331) 21,478 (855)
--------- --------- --------- ---------
TOTAL 97,036 152,975 316,996 344,361
--------- --------- --------- ---------
OPERATING INCOME (LOSS) 17,419 (308) 50,527 16,384
Nonoperating Income 23,581 15,446 54,877 20,938
Nonoperating Expenses 15,220 13,639 43,892 20,898
Nonoperating Income Tax Expense (Credit) 2,707 599 3,188 (33)
Interest Charges 5,726 5,093 16,290 15,983
--------- --------- --------- ---------
Income (Loss) Before Cumulative Effect of Accounting Changes 17,347 (4,193) 42,034 474
Cumulative Effect of Accounting Changes (Net of Tax) - - 3,071 -
--------- --------- --------- ---------
NET INCOME (LOSS) 17,347 (4,193) 45,105 474
Preferred Stock Dividend Requirements 26 26 78 78
--------- --------- --------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $17,321 $(4,219) $45,027 $396
========= ========= ========= =========
The common stock of TNC is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
JANUARY 1, 2002 $137,214 $2,351 $105,970 $- $245,535
Common Stock Dividends (20,247) (20,247)
Preferred Stock Dividends (78) (78)
---------
TOTAL 225,210
---------
COMPREHENSIVE INCOME
- -----------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 17 17
NET INCOME 474 474
---------
TOTAL COMPREHENSIVE INCOME 491
--------- ------- -------- --------- ---------
SEPTEMBER 30, 2002 $137,214 $2,351 $86,119 $17 $225,701
========= ======= ========= ========= =========
JANUARY 1, 2003 $137,214 $2,351 $71,942 $(30,763) $180,744
Common Stock Dividends (4,970) (4,970)
Preferred Stock Dividends (78) (78)
Capital Stock Gain 3 3
---------
TOTAL 175,699
---------
COMPREHENSIVE INCOME
- ------------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 130 130
Unrealized Loss on Minimum Pension
Liability (7) (7)
NET INCOME 45,105 45,105
---------
TOTAL COMPREHENSIVE INCOME 45,228
--------- ------- --------- --------- ---------
SEPTEMBER 30, 2003 $137,214 $2,351 $112,002 $(30,640) $220,927
========= ======= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ------------------------------------------------------------
Production $358,020 $353,087
Transmission 266,468 254,483
Distribution 454,255 445,486
General 113,303 111,679
Construction Work in Progress 31,171 37,012
---------- ----------
TOTAL 1,223,217 1,201,747
Accumulated Depreciation and Amortization 531,854 521,792
---------- ----------
TOTAL - NET 691,363 679,955
---------- ----------
Other Property and Investments 1,167 1,213
Long-term Risk Management Assets 6,214 2,248
CURRENT ASSETS
- ------------------------------------------------------------
Cash and Cash Equivalents 2,742 1,219
Advances to Affiliates 15,075 -
Accounts Receivable:
Customers 62,254 62,660
Affiliated Companies 29,395 43,632
Allowance for Uncollectible Accounts (261) (5,041)
Fuel Inventory 8,821 12,677
Materials and Supplies 10,772 9,574
Accrued Utility Revenues 5,888 6,829
Risk Management Assets 5,154 4,130
Prepayments and Other 1,243 1,070
---------- ----------
TOTAL 141,083 136,750
---------- ----------
Regulatory Assets 42,426 45,097
Deferred Charges 30,321 11,912
TOTAL ASSETS $912,574 $877,175
========== ==========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Accumulated Other Comprehensive Income (Loss) (30,640) (30,763)
Retained Earnings 112,002 71,942
--------- ---------
Total Common Shareholder's Equity 220,927 180,744
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,357 2,367
Long-term Debt 332,686 132,500
--------- ---------
TOTAL 555,970 315,611
--------- ---------
Other Noncurrent Liabilities 41,911 28,861
CURRENT LIABILITIES
- ------------------------------------------------------------
Short-term Debt - Affiliates - 125,000
Long-term Debt Due Within One Year 24,036 -
Advances from Affiliates - 80,407
Accounts Payable:
General 36,187 32,714
Affiliated Companies 32,196 76,217
Customer Deposits 209 117
Taxes Accrued 11,769 3,697
Interest Accrued 4,266 2,776
Risk Management Liabilities 2,309 3,801
Other 13,040 17,414
--------- ---------
TOTAL 124,012 342,143
--------- ---------
Deferred Income Taxes 119,802 117,521
Deferred Investment Tax Credits 20,370 21,510
Long-term Risk Management Liabilities 2,033 557
Regulatory Liabilities and Deferred Credits 48,476 50,972
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $912,574 $877,175
========= =========
See Notes to Respective Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- ------------------------------------------------------------
Net Income $45,105 $474
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 26,387 34,154
Write Down of Utility Plant Assets - 34,215
Deferred Income Taxes 231 (14,139)
Deferred Investment Tax Credits (1,140) (953)
Cumulative Effect of Accounting Changes (3,071) -
Mark-to-Market of Risk Management Contracts (4,786) (2,863)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 9,863 (41,364)
Fuel, Materials and Supplies 2,658 (3,969)
Accrued Utility Revenues 941 -
Accounts Payable (40,548) (7,012)
Taxes Accrued 8,072 11,998
Fuel Recovery - 9,161
Deferred Property Taxes (3,323) (3,588)
Change in Other Assets (13,093) (13,603)
Change in Other Liabilities 7,308 113
--------- --------
Net Cash Flows From Operating Activities 34,604 2,624
--------- --------
INVESTING ACTIVITIES
- ------------------------------------------------------------
Construction Expenditures (33,136) (33,338)
Other 595 -
--------- --------
Net Cash Flows Used For Investing Activities (32,541) (33,338)
--------- --------
FINANCING ACTIVITIES
- ------------------------------------------------------------
Change in Short-term Debt-Affiliates (125,000) -
Issuance of Long-term Debt 225,000 -
Retirement of Long-term Debt - (95,799)
Retirement of Preferred Stock (10) -
Change in Advances to/from Affiliates, Net (95,482) 144,726
Dividends Paid on Common Stock (4,970) (20,247)
Dividends Paid on Cumulative Preferred Stock (78) (78)
--------- --------
Net Cash Flows From (Used For) Financing Activities (540) 28,602
--------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 1,523 (2,112)
Cash and Cash Equivalents at Beginning of Period 1,219 2,454
--------- --------
Cash and Cash Equivalents at End of Period $2,742 $342
========= ========
SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $12,990,000 and
$13,061,000 and for income taxes was $16,410,000 and $2,408,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income for the first nine months of 2003 increased $61 million over the
prior year period primarily due to the Cumulative Effect of Accounting Changes
of $77 million recorded in the first quarter of 2003. This increase was
partially offset by a $12 million decrease in net nonoperating income primarily
due to reduced gains from risk management activities and increased Interest
Charges of $5 million due to the effects of refinancing activities.
Net Income for the third quarter of 2003 decreased $8 million primarily due to
an $18 million increase in capacity charges included in Purchased Electricity
from AEP Affiliates partially offset by increased earnings from system sales and
increased net nonoperating income. The cost of the AEP Power Pool's generating
capacity is allocated among the Pool members based on their relative peak
demands and generating reserves through the payment of capacity charges and the
receipt of capacity credits. We, as a member of the AEP Power Pool, share in the
revenues and costs of marketing and activities conducted on our behalf by the
AEP Power Pool. Our relative share of the AEP Power Pool revenues and expenses
increased over the prior periods as a result of our reaching a new peak demand
in January 2003, which increased our allocation factor.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income for the third quarter of 2003 decreased by $14 million from
2002 primarily due to the following:
o An increase in purchased power and fuel expense of $45 million
reflecting the $18 million increase in capacity charges described
above, the increase in our relative share of the AEP Power Pool
expenses and the recently increased cost of coal.
o A decline in retail sales of $8 million resulting from decreased
residential sales reflecting the mild weather conditions combined
with lower industrial sales reflecting the continued weak economy.
Cooling degree days for the quarter decreased 25% from the prior
period.
o An $11 million decrease due to reduced gains from risk management
activities.
The decrease in Operating Income for the third quarter of 2003 was partially
offset by:
o An increase in system sales and transmission revenues totaling $29
million reflecting an increase in the volume of AEP Power Pool
transactions, as well as our relative share based on the higher
allocation factor.
o An increase of $9 million in Sales to AEP Affiliates.
o A decrease in income taxes of $7 million primarily due to the decrease
in pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income increased $1 million for the third quarter primarily due to
increased interest income on investments in the AEP Money Pool. The $2 million
decrease in Nonoperating Income Tax Expense for third quarter was primarily due
to a tax adjustment related to consolidated tax savings.
Interest Charges decreased $2 million for the third quarter primarily due to the
early retirement of First Mortgage Bonds in the second quarter of 2003 partially
offset by increased interest expense from a higher average balance of Senior
Unsecured Notes (see Financing Activities section below).
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income for the first nine months of 2003 was relatively flat compared
to the prior year.
The positive factors affecting Operating Income are as follows:
o System sales and transmission revenues increased $71 million over
2002, due to increased system sales volume, as well as our
relative share based on the higher allocation factor.
o An increase in Sales to AEP Affiliates of $28 million.
o A decrease in Depreciation and Amortization expense of $13 million
due primarily to the adoption of SFAS 143 (see Note 2).
Additionally, we have reduced depreciation and amortization
expense related to the amortization of generation related
regulatory assets over the transition period due to the return to
SFAS 71 for the West Virginia jurisdiction in the first quarter of
2003.
o An increase in gains from risk management activities of $12 million.
These increases in Operating Income for the first nine months of 2003 were
offset by:
o An increase of $112 million in purchased power and fuel expense
primarily due to a $41 million increase in capacity charges, the
increase in our relative share of AEP Power Pool expenses and the
recently increased cost of coal.
o An increase in Maintenance expense of $16 million, due primarily
to increased maintenance at Amos and Sporn plants and maintenance
of overhead lines required due to severe storm damage in the first
quarter of 2003.
Other Impacts on Earnings
Nonoperating Income decreased $24 million for the nine months ended September
30, 2003, primarily due to a decrease in gains from risk management activities.
Nonoperating Income Tax decreased $13 million for the nine months ended
September 30, 2003 due to a decrease in pre-tax nonoperating book income and a
tax adjustment related to consolidated tax savings.
Interest Charges increased $5 million for the nine months ended September 30,
2003, due to decreased AFUDC credits in 2003 compared to 2002 and call premiums
relating to retirement of First Mortgage Bonds and Installment Purchase
Contracts. (See Financing Activities).
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes of $77 million is due to the
implementation of SFAS 143 and EITF 02-03 (see Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are
as follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB A-
Senior Unsecured Debt Baa2 BBB BBB+
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from Baa1 to Baa2 and a downgrade of secured
ratings from A3 to Baa1. The completion of this review was a culmination of
ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.
Cash Flow
Cash flows for nine months ended September 30, 2003 and 2002 were as follows:
2003 2002
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $4,285 $13,663
Cash flow from (used for):
Operating activities 404,828 229,160
Investing activities (187,969) (171,831)
Financing activities (215,877) (61,564)
--------- ---------
Net increase (decrease) in cash and cash equivalents 982 (4,235)
--------- ---------
Cash and cash equivalents at end of period $5,267 $9,428
========= =========
Operating Activities
Cash flow from operating activities increased $176 million primarily due to
decreases in various accounts receivable balances in the nine months ended
September 30, 2003.
Investing Activities
Construction expenditures in 2003 versus 2002 increased $15 million. The current
year expenditures of $190 million were focused primarily on projects to improve
service reliability for transmission and distribution, as well as environmental
upgrades.
Financing Activities
In 2003, we issued two series of Senior Unsecured Notes, each in the amount of
$200 million which were used to call First Mortgage Bonds and fund maturities.
Additionally, we incurred obligations of $100 million in Installment Purchase
Contracts which were used to redeem higher costing Installment Purchase
Contracts.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Senior Unsecured Notes $200 3.60 2008
Senior Unsecured Notes 200 5.95 2033
Installment Purchase
Contracts 100 5.50 2022
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
First Mortgage Bonds $70 8.50 2022
First Mortgage Bonds 30 7.80 2023
First Mortgage Bonds 20 7.15 2023
Installment Purchase
Contracts 10 7.875 2013
Installment Purchase
Contracts 40 6.85 2022
Installment Purchase
Contracts 50 6.60 2022
Senior Unsecured Notes 100 7.20 2038
Senior Unsecured Notes 100 7.30 2038
Senior Unsecured Notes 125 Variable 2003
Significant Factors
- -------------------
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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The Federal EPA and a number of states
alleged APCo and certain affiliated companies 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 AEP
subsidiaries in U.S. District Court for the Southern District of Ohio. A
separate lawsuit initiated by certain special interest groups was consolidated
with the Federal EPA case. The alleged modification of the generating units
occurred over a 20 year period.
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 we do not prevail, any capital and operating costs of
additional pollution control equipment that may be required as well as any
penalties imposed would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity. See Note 5 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.
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 of approximately $464 million. 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, these costs would adversely affect future results of
operations, cash flows and possibly financial condition (see Note 5).
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 AEP's transmission
system to RTOs. Furthermore, legislation in certain states in which AEP
subsidiaries operate requires RTO participation.
In May 2002, AEP 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 AEP's 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, we filed with the Virginia SCC for approval of our plan to
transfer functional control of our transmission assets to PJM. 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.
We are 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 (see Note 3).
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $96,852
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (34,984)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 265
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (4,664)
Changes in Fair Value of Risk Management
Contracts (d) 2,022
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) (1,030)
--------
Total MTM Risk Management Contract Net
Assets 58,461
Net Non-Trading Related Derivative
Contracts 1,561
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $60,022
========
(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, 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.
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
our total MTM asset or liability (external sources or
modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(291) $53 $(266) $- $- $- $(504)
Prices Provided by Other External Sources -
OTC Broker Quotes (a) 1,259 14,602 6,200 5,436 1,287 - 28,784
Prices Based on Models and Other Valuation
Methods (b) 2,109 5,098 3,236 3,913 4,315 11,510 30,181
------- -------- ------- ------- ------- -------- --------
Total $3,077 $19,753 $9,170 $9,349 $5,602 $11,510 $58,461
======= ======== ====== ======= ======= ======== ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic Foreign
Power Currency Interest Rate Consolidated
-------- -------- ------------- ------------
(in thousands)
Accumulated OCI, December 31, 2002 $(394) $(190) $(1,336) $(1,920)
Changes in Fair Value (a) 785 - (719) 66
Reclassifications from OCI to Net
Income (b) 475 5 226 706
------ ------ -------- --------
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $866 $(185) $(1,829) $(1,148)
====== ====== ======== ========
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,167 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$800 $2,271 $1,046 $226 $1,289 $3,948 $1,412 $286
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------------------
Electric Generation, Transmission and Distribution $428,667 $418,159 $1,297,255 $1,220,039
Sales to AEP Affiliates 54,944 46,250 167,335 138,990
--------- --------- ----------- -----------
TOTAL 483,611 464,409 1,464,590 1,359,029
--------- --------- ----------- -----------
OPERATING EXPENSES
- ----------------------------------------------------------
Fuel for Electric Generation 113,274 107,514 345,819 322,164
Purchased Electricity for Resale 18,365 13,174 50,745 41,635
Purchased Electricity from AEP Affiliates 92,857 58,395 257,382 177,892
Other Operation 64,065 67,255 192,806 197,631
Maintenance 31,855 32,053 101,420 85,542
Depreciation and Amortization 46,501 47,692 128,574 141,373
Taxes Other Than Income Taxes 23,232 23,881 70,583 73,926
Income Taxes 26,328 33,080 88,387 90,723
--------- --------- ----------- -----------
TOTAL 416,477 383,044 1,235,716 1,130,886
--------- --------- ----------- -----------
OPERATING INCOME 67,134 81,365 228,874 228,143
Nonoperating Income 7,809 6,627 2,878 26,644
Nonoperating Expenses 4,217 4,865 10,219 9,170
Nonoperating Income Tax
Expense (Credit) (1,307) 538 (7,491) 5,622
Interest Charges 26,318 28,642 89,520 84,099
--------- --------- ----------- -----------
Income Before Cumulative Effect
of Accounting Changes 45,715 53,947 139,504 155,896
Cumulative Effect of Accounting Changes (Net of Tax) - - 77,257 -
--------- --------- ----------- -----------
NET INCOME 45,715 53,947 216,761 155,896
Preferred Stock Dividend Requirements
(Including Capital Stock Expense) 703 502 2,671 1,508
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $45,012 $53,445 $214,090 $154,388
========= ========= =========== ===========
The common stock of APCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
JANUARY 1, 2002 $260,458 $715,786 $150,797 $(340) $1,126,701
Common Stock Dividends (92,952) (92,952)
Preferred Stock Dividends (1,082) (1,082)
Capital Stock Expense 426 (426) -
-----------
TOTAL 1,032,667
-----------
COMPREHENSIVE INCOME
- --------------------------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow Hedges (1,387) (1,387)
NET INCOME 155,896 155,896
-----------
TOTAL COMPREHENSIVE INCOME 154,509
--------- --------- --------- --------- -----------
SEPTEMBER 30, 2002 $260,458 $716,212 $212,233 $ (1,727) $1,187,176
--------- --------- --------- --------- -----------
JANUARY 1, 2003 $260,458 $717,242 $260,439 $(72,082) $1,166,057
Common Stock Dividends (96,200) (96,200)
Preferred Stock Dividends (801) (801)
Capital Stock Expense 1,870 (1,870) -
SFAS 71 Reapplication 162 162
-----------
TOTAL 1,069,218
-----------
COMPREHENSIVE INCOME
- --------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 772 772
NET INCOME 216,761 216,761
-----------
TOTAL COMPREHENSIVE INCOME 217,533
--------- --------- --------- --------- -----------
SEPTEMBER 30, 2003 $260,458 $719,274 $378,329 $(71,310) $1,286,751
========= ========= ========= ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------------------
Production $2,286,567 $2,245,945
Transmission 1,236,108 1,218,108
Distribution 1,991,491 1,951,804
General 280,309 272,901
Construction Work in Progress 254,387 206,545
----------- -----------
TOTAL 6,048,862 5,895,303
Accumulated Depreciation and Amortization 2,381,700 2,424,607
----------- -----------
TOTAL - NET 3,667,162 3,470,696
----------- -----------
Other Property and Investments 49,356 54,653
Long-term Risk Management Assets 83,520 115,748
CURRENT ASSETS
- ----------------------------------------------------------
Cash and Cash Equivalents 5,267 4,285
Advances to Affiliates 34,434 -
Accounts Receivable:
Customers 110,481 132,266
Affiliated Companies 90,591 122,665
Miscellaneous 26,072 28,629
Allowance for Uncollectible Accounts (2,570) (13,439)
Fuel Inventory 33,235 53,646
Materials and Supplies 74,095 59,886
Accrued Utility Revenues 7,822 30,948
Risk Management Assets 57,957 94,238
Prepayments and Other 16,833 13,396
----------- -----------
TOTAL 454,217 526,520
----------- -----------
Regulatory Assets 402,559 395,553
Deferred Charges 45,562 64,677
TOTAL ASSETS $4,702,376 $4,627,847
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- ----------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $260,458 $260,458
Paid-in Capital 719,274 717,242
Accumulated Other Comprehensive Income (Loss) (71,310) (72,082)
Retained Earnings 378,329 260,439
----------- -----------
Total Common Shareholder's Equity 1,286,751 1,166,057
Cumulative Preferred Stock Not Subject to Mandatory Redemption 17,790 17,790
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,802,332 1,738,854
----------- -----------
TOTAL 3,117,733 2,933,561
----------- -----------
Other Noncurrent Liabilities 190,379 173,438
CURRENT LIABILITIES
- ----------------------------------------------------------
Long-term Debt Due Within One Year 51,008 155,007
Advances from Affiliates - 39,205
Accounts Payable:
General 120,319 141,546
Affiliated Companies 61,670 98,374
Taxes Accrued 47,182 29,181
Customer Deposits 31,776 26,186
Interest Accrued 42,791 22,437
Risk Management Liabilities 36,278 69,001
Other 70,473 79,832
----------- -----------
TOTAL 461,497 660,769
----------- -----------
Deferred Income Taxes 755,125 701,801
Deferred Investment Tax Credits 31,752 33,691
Long-term Risk Management Liabilities 45,177 44,517
Regulatory Liabilities and Deferred Credits 100,713 80,070
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $4,702,376 $4,627,847
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- ----------------------------------------------------------
Net Income $216,761 $155,896
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes (77,257) -
Depreciation and Amortization 128,574 141,457
Deferred Income Taxes 3,394 10,257
Deferred Investment Tax Credits (1,940) (3,295)
Deferred Power Supply Costs, Net 71,815 -
Mark to Market of Risk Management Contracts 33,727 (27,710)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 45,547 (83,288)
Fuel, Materials and Supplies 6,202 5,176
Accrued Utility Revenues 23,126 7,547
Accounts Payable (57,931) (26,948)
Taxes Accrued 18,001 39,660
Interest Accrued 20,354 13,487
Incentive Plan Accrued (8,789) -
Rate Stabilization Deferral (75,601) -
Change in Other Assets 19,748 (7,697)
Change in Other Liabilities 39,097 4,618
--------- ---------
Net Cash Flows From Operating Activities 404,828 229,160
--------- ---------
INVESTING ACTIVITIES
- ----------------------------------------------------------
Construction Expenditures (190,047) (175,314)
Proceeds from Sale of Property and Other 2,078 3,483
--------- ---------
Net Cash Flows Used For Investing Activities (187,969) (171,831)
--------- ---------
FINANCING ACTIVITIES
- ----------------------------------------------------------
Issuance of Long-term Debt 500,000 444,110
Change in Advances to/from Affiliates, Net (73,639) (126,640)
Retirement of Long-term Debt (545,237) (285,000)
Dividends Paid on Common Stock (96,200) (92,952)
Dividends Paid on Cumulative Preferred Stock (801) (1,082)
--------- ---------
Net Cash Flows Used For Financing Activities (215,877) (61,564)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 982 (4,235)
Cash and Cash Equivalents at Beginning of Period 4,285 13,663
--------- ---------
Cash and Cash Equivalents at End of Period $5,267 $9,428
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $63,481,000 and
$68,305,000 and for income taxes was $47,419,000 and $38,425,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
The decrease in Net Income of $13 million in the third quarter of 2003 compared
to the third quarter of 2002 was primarily due to a $27 million decrease in
retail electricity sales and a $12 million decrease in revenues from risk
management activities, which were partially offset by a $4 million increase in
sales to AEP affiliated companies and a $23 million decrease in income taxes. As
a member of the AEP Power Pool, we share in the revenues and costs of marketing
and activities conducted by the AEP Power Pool on our behalf.
The decrease in Net Income of $4 million for the nine months ended September 30,
2003 compared to the same period in 2002 was primarily due to a $41 million
increase in fuel and purchased power expenses and a $28 million decrease in
revenues from risk management activities, partially offset by a $31 million
decrease in income taxes and a $27 million net-of-tax Cumulative Effect of
Accounting Changes.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income decreased by $18 million primarily due to:
o Milder weather and a sluggish economy that resulted in decreased
retail revenues of $27 million. Cooling degree days for the
quarter decreased 36% from the prior period.
o A $10 million decrease in risk management income due to unfavorable
market conditions and reduced activity.
o Increased purchased electricity of $10 million due to increased usage
of the AEP Power Pool to meet load requirements.
o An increase of $5 million in Maintenance expense due to boiler
overhaul work from scheduled and forced outages and
maintenance of overhead lines resulting from severe storm damage.
The decrease in Operating Income was partially offset by:
o An increase of $4 million in Sales to AEP Affiliates.
o A decrease in Other Operation expense of $5 million primarily due
to decreases in factored receivable expenses, AEP transmission
equalization expenses and miscellaneous distribution expenses.
o A decrease in Income Taxes of $18 million primarily due to a decrease
in pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income Tax Expense decreased $5 million primarily due to a tax
adjustment related to consolidated tax savings.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income decreased $23 million primarily due to:
o Milder spring and summer weather and a sluggish economy resulting
in decreased retail revenues of $37 million. Cooling degree days
have decreased 41% year-to-date from the prior period.
o An increase in the AEP system pool capacity charge of $5 million.
o A $13 million increase in Maintenance expense due primarily to
boiler overhaul work from scheduled and forced outages and
maintenance of overhead lines resulting from severe storm damage.
o A $10 million increase in fuel expense due to higher coal costs.
o An increase of $28 million in Purchased Electricity from AEP
Affiliates due to increased load requirements.
The decrease in Operating Income was partially offset by:
o An increase of $20 million of Sales to AEP Affiliates and an increase
of $25 million of sales to non-affiliates.
o A decrease in Other Operation expense of $12 million primarily due to
decreases in factored receivable expenses, AEP transmission
equalization expenses and miscellaneous distribution expenses.
o Income Taxes decreased by $17 million primarily due to a decrease in
pre-tax operating book income.
Other Impacts on Earnings
Nonoperating Income decreased $22 million primarily due to a reduction of risk
management activities as a result of AEP's decision to exit wholesale markets
where it does not own assets.
Nonoperating Income Tax Credit increased due to a decrease in pre-tax
nonoperating book income and a tax adjustment related to consolidated tax
savings.
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt A3 BBB A-
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Senior Unsecured Notes $250 5.50 2013
Senior Unsecured Notes 250 6.60 2033
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
First Mortgage Bonds $2 8.70 2022
First Mortgage Bonds 15 8.55 2022
First Mortgage Bonds 14 8.40 2022
First Mortgage Bonds 13 8.40 2022
First Mortgage Bonds 13 6.80 2003
First Mortgage Bonds 26 6.55 2004
First Mortgage Bonds 26 6.75 2004
First Mortgage Bonds 40 7.90 2023
First Mortgage Bonds 33 7.75 2023
First Mortgage Bonds 25 6.60 2003
Intercompany Retirement of Debt Due to AEP
------------------------------------------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Notes Payable $160 6.501 2006
Significant Factors
- -------------------
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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The Federal EPA and a number of states
alleged CSPCo, certain affiliated companies 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 us 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 we do not prevail, any capital and operating costs of
additional pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity. See Note 5 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.
We are installing 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 of approximately $87 million. The actual cost to comply
could be significantly different than the estimate 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 5 for further discussion.
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $65,117
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (23,524)
Fair Value of New Contracts When Entered Into During
the Period (b) -
Net Option Premiums Paid/(Received) (c) 149
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (3,135)
Changes in Fair Value of Risk Management
Contracts (d) (5,681)
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
--------
Total MTM Risk Management Contract Net
Assets 32,926
Net Non-Trading Related Derivative
Contracts 901
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $33,827
========
(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, 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
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
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
our total MTM asset or liability (external sources or
modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(164) $30 $(150) $- $- $- $(284)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 709 8,224 3,492 3,061 725 - 16,211
Prices Based on Models and Other
Valuation Methods (b) 1,189 2,871 1,823 2,204 2,430 6,482 16,999
------- -------- ------- ------- ------- ------- --------
Total $1,734 $11,125 $5,165 $5,265 $3,155 $6,482 $32,926
======= ======== ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power
--------
(in thousands)
Accumulated OCI, December 31, 2002 $(267)
Changes in Fair Value (a) 484
Reclassifications from OCI to Net
Income (b) 271
------
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $ 488
======
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $851 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$450 $1,279 $589 $127 $867 $2,654 $949 $192
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------------
Electric Generation, Transmission and Distribution $375,936 $404,568 $1,027,732 $1,038,254
Sales to AEP Affiliates 21,719 17,324 62,199 42,277
--------- --------- ----------- -----------
TOTAL 397,655 421,892 1,089,931 1,080,531
--------- --------- ----------- -----------
OPERATING EXPENSES
- --------------------------------------------------------
Fuel for Electric Generation 50,355 47,228 146,422 135,942
Purchased Electricity for Resale 5,688 3,569 13,898 11,124
Purchased Electricity from AEP Affiliates 93,486 85,228 263,225 235,432
Other Operation 57,348 62,393 166,027 178,042
Maintenance 19,630 14,878 56,801 44,068
Depreciation and Amortization 34,442 33,450 101,478 98,588
Taxes Other Than Income Taxes 34,970 37,570 101,532 97,176
Income Taxes 30,543 48,543 70,787 87,538
--------- --------- ----------- -----------
TOTAL 326,462 332,859 920,170 887,910
--------- --------- ----------- -----------
OPERATING INCOME 71,193 89,033 169,761 192,621
Nonoperating Income (Loss) 4,169 5,360 (2,587) 19,751
Nonoperating Expenses 550 1,014 2,944 1,432
Nonoperating Income Tax Expense (Credit) (84) 4,590 (5,231) 9,387
Interest Charges 12,071 12,672 38,946 39,857
--------- --------- ----------- -----------
Income Before Cumulative Effect of Accounting Changes 62,825 76,117 130,515 161,696
Cumulative Effect of Accounting Changes (Net of Tax) - - 27,283 -
--------- --------- ----------- -----------
NET INCOME 62,825 76,117 157,798 161,696
Preferred Stock Dividend Requirements (Including
Capital Stock Expense) 254 254 762 1,112
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $62,571 $75,863 $157,036 $160,584
========= ========= =========== ===========
The common stock of CSPCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on Page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
JANUARY 1, 2002 $41,026 $574,369 $176,103 $791,498
Common Stock Dividends Declared (65,300) (65,300)
Preferred Stock Dividends Declared (350) (350)
Capital Stock Expense 762 (762) -
---------
725,848
---------
COMPREHENSIVE INCOME
- ---------------------------------------------------
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges $326 326
NET INCOME 161,696 161,696
---------
TOTAL COMPREHENSIVE INCOME 162,022
-------- --------- --------- --------- ---------
SEPTEMBER 30, 2002 $41,026 $575,131 $271,387 $326 $887,870
-------- --------- --------- --------- ---------
JANUARY 1, 2003 $41,026 $575,384 $290,611 $(59,357) $847,664
Common Stock Dividends Declared (124,932) (124,932)
Capital Stock Expense 762 (762) -
---------
722,732
---------
COMPREHENSIVE INCOME
- ---------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges 755 755
NET INCOME 157,798 157,798
---------
TOTAL COMPREHENSIVE INCOME 158,553
-------- --------- --------- --------- ---------
SEPTEMBER 30, 2003 $41,026 $576,146 $322,715 $(58,602) $881,285
======== ========= ========= ========= ---------
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------------
Production $1,601,987 $1,582,627
Transmission 422,717 413,286
Distribution 1,247,229 1,208,255
General 158,810 165,025
Construction Work in Progress 107,581 98,433
----------- -----------
TOTAL 3,538,324 3,467,626
Accumulated Depreciation and Amortization 1,468,746 1,465,174
----------- -----------
TOTAL - NET 2,069,578 2,002,452
----------- -----------
Other Property and Investments 31,840 35,759
Long-term Risk Management Assets 47,039 77,810
CURRENT ASSETS
- --------------------------------------------------------
Cash and Cash Equivalents 4,909 1,479
Advances to Affiliates, Net - 31,257
Accounts Receivable:
Customers 33,157 49,566
Affiliated Companies 40,385 54,518
Miscellaneous 21,090 22,005
Allowance for Uncollectible Accounts (575) (634)
Fuel 15,231 24,844
Materials and Supplies 46,626 40,339
Accrued Utility Revenues 16,963 12,671
Risk Management Assets 32,664 63,348
Prepayments and Other 10,458 7,308
----------- -----------
TOTAL 220,908 306,701
----------- -----------
Regulatory Assets 247,403 257,682
Deferred Charges 35,047 72,836
TOTAL ASSETS $2,651,815 $2,753,240
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- --------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $41,026 $41,026
Paid-in Capital 576,146 575,384
Accumulated Other Comprehensive Income (Loss) (58,602) (59,357)
Retained Earnings 322,715 290,611
----------- -----------
Total Common Shareholder's Equity 881,285 847,664
----------- -----------
Long-term Debt:
Nonaffiliated 747,806 418,626
Affiliated - 160,000
Total Long-term Debt 747,806 578,626
----------- -----------
TOTAL 1,629,091 1,426,290
----------- -----------
Other Noncurrent Liabilities 88,683 95,460
CURRENT LIABILITIES
- --------------------------------------------------------
Long-term Debt Due Within One Year - Nonaffiliated 5,000 43,000
Short-term Debt - Affiliates - 290,000
Advances from Affiliates, Net 151,575 -
Accounts Payable - General 53,325 89,736
Accounts Payable - Affiliated Companies 43,603 81,599
Taxes Accrued 78,304 112,172
Interest Accrued 7,744 9,798
Risk Management Liabilities 20,432 46,375
Other 51,021 36,790
----------- -----------
TOTAL 411,004 709,470
----------- -----------
Deferred Income Taxes 451,638 437,771
Deferred Investment Tax Credits 31,619 33,907
Long-term Risk Management Liabilities 25,444 29,926
Deferred Credits and Regulatory Liabilities 14,336 20,416
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,651,815 $2,753,240
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $157,798 $161,696
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes (27,283) -
Depreciation and Amortization 101,478 98,666
Deferred Income Taxes (3,942) 12,450
Deferred Investment Tax Credits (2,288) (2,335)
Mark-to-Market of Risk Management Contracts 29,056 (21,033)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 31,398 (33,529)
Fuel, Materials and Supplies 3,326 (2,391)
Accrued Utility Revenues (4,292) (14,925)
Prepayments and Other Current Assets (3,150) (6,991)
Accounts Payable (74,407) (10,506)
Taxes Accrued (33,868) 5,597
Interest Accrued (2,054) 1,485
Deferred Property Tax 46,478 31,968
Change in Other Assets (12,882) (3,155)
Change in Other Liabilities (4,496) 10,733
--------- ---------
Net Cash Flows From Operating Activities 200,872 227,730
--------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (98,032) (88,101)
Proceeds from Sale of Property 190 730
--------- ---------
Net Cash Flows Used For Investing Activities (97,842) (87,371)
--------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------
Issuance of Long-term Debt 500,000 160,000
Change in Advances to/from Affiliates, Net 182,832 (206,501)
Retirement of Long-term Debt - Nonaffiliated (207,500) (112,843)
Retirement of Long-term Debt - Affiliated (160,000) (200,000)
Retirement of Cumulative Preferred Stock - (10,000)
Change in Short-term Debt - Affiliates (290,000) 290,000
Dividends Paid on Common Stock (124,932) (65,300)
Dividends Paid on Cumulative Preferred Stock - (525)
--------- ---------
Net Cash Flows Used For Financing Activities (99,600) (145,169)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 3,430 (4,810)
Cash and Cash Equivalents at Beginning of Period 1,479 12,358
--------- ---------
Cash and Cash Equivalents at End of Period $4,909 $7,548
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $39,804,000 and
$37,204,000 and for income taxes was $48,955,000 and $32,254,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
In the third quarter of 2003, Net Income increased $2 million reflecting reduced
financing costs. Net Income increased $10 million including an unfavorable $3
million Cumulative Effect of Accounting Change in the first nine months of 2003
(see Note 2). For the nine months ended September 30, 2003, Net Income Before
Cumulative Effect of Accounting Change increased $13 million due to an
improvement in earnings primarily during the first quarter of 2003 from retail
and AEP Power Pool sales resulting from the interactions of plant availability,
colder winter weather and higher margins partially offset by the weak economy.
As a member of the AEP Power Pool, we share in the revenues and costs of
marketing and activities conducted by the AEP Power Pool on our behalf.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income decreased less than $1 million primarily due to:
o Decreased retail revenues of $22 million due primarily to milder
weather during the third quarter of 2003 and economic pressures on
industrial customers. Cooling degree days declined approximately
33% this year compared with last year. Industrial revenues dropped
5% from last year.
o Increased Fuel for Electric Generation expense of $2 million
reflecting an increase in the average cost of fuel.
o Increased Purchased Electricity from AEP Affiliates of $9 million due
to purchasing more power from the AEP Power Pool to support wholesale
sales to unaffiliated entities.
The decrease in Operating Income during the third quarter was offset by:
o Increased sales to AEP Affiliates of $6 million due to increased
capacity revenue.
o Increased wholesale sales including system and power optimization
sales, transmission revenues and risk management activities of $25
million reflecting availability of AEP's generation and market
conditions.
o A $3 million decrease in Maintenance expense due to an insurance
recovery for costs incurred related to an influx of fish at Cook Plant.
See Significant Factors section below.
Other Impacts on Earnings
Interest Charges decreased $4 million in the third quarter primarily due to a
reduction in outstanding long-term debt of $255 million which was retired in May
2003 using lower rate short-term debt.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income increased $27 million primarily due to the following:
o Wholesale revenues increased $61 million reflecting market conditions.
o Sales to AEP Affiliates increased by $43 million due to more power
being available for sale in 2003 and increased capacity revenues.
In 2002, both units of Cook plant was shut down for refueling and
both Rockport units were down for planned boiler maintenance.
o A decline in Other Operation expense of $22 million due to the
impact of cost reduction efforts instituted in the fourth quarter
of 2002 and having two refueling outages in 2002 versus one
refueling outage in 2003.
o An $8 million decrease in Taxes Other Than Income Taxes reflects a
favorable tax law change in Indiana effective March 2002 and a
lower estimate for Cook Plant's assessed value, which reduced real
and personal property tax estimates on which 2003 accruals are
based.
The year-to-date increase in Operating Income was partially offset by:
o A $23 million decline in retail revenues reflecting milder summer
weather and lower industrial sales reflecting economic pressure.
o Increased Fuel for Electric Generation expense of $33 million
reflecting an increase in the average cost of fuel and increased
generation.
o Increased Purchased Electricity from AEP Affiliates of $31 million
due to higher power purchases from AEGCo and the AEP Power Pool in
2003 compared to 2002 when outages at both units of the Rockport
Plant decreased available power and purchases of replacement power
during 2003 Cook forced outages.
o Increased Income Taxes of $11 million reflecting an increase in
pre-tax income.
Other Impacts on Earnings
Nonoperating Income decreased $20 million year-to-date primarily due to lower
margins for power sold outside of AEP's traditional marketing area reflecting
AEP's plan to exit those risk management activities.
Interest Charges decreased $6 million year-to-date primarily due to a reduction
in outstanding long-term debt of $255 million which was retired in May 2003
using lower rate short-term debt.
Cumulative Effect of Accounting Change
The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB BBB+
Senior Unsecured Debt Baa2 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 its
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.
Cash Flow
Cash flows for nine months ended September 30, 2003 and 2002 were as follows:
2003 2002
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $3,237 $16,804
Cash flow from (used for):
Operating activities 191,018 161,460
Investing activities (106,546) (91,360)
Financing activities (83,634) (77,902)
--------- --------
Net increase (decrease) in cash and cash equivalents 838 (7,802)
--------- --------
Cash and cash equivalents at end of period $4,075 $9,002
========= ========
Operating Activities
Operating activities during the first nine months of 2003 provided $30 million
more cash than during 2002 largely due to the year-over-year increase in net
income of $10 million and a $51 million increase in the change in mark-to-market
of risk management contracts offset by a $43 million decrease in accrued taxes.
Investing Activities
Cash flows used for investing activities during the first nine months of 2003
were $107 million compared to $91 million during 2002. The primary reason for
the year-over-year variance was a construction expenditures increase of $16
million. Construction expenditures for the nuclear plant and transmission and
distribution assets are to upgrade or replace equipment and improve reliability.
Financing Activities
Financing activities for the nine months ended September 30, 2003 used $6
million more than 2002 primarily due to dividends paid on common stock as none
were paid in 2002.
Financing Activity
Long-term debt issuances and retirements (using short-term debt) during the
first nine months of 2003 were:
Issuances
---------
None
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
First Mortgage Bonds $ 75 8.50 2022
First Mortgage Bonds 15 7.35 2023
Junior Debentures 40 8.00 2026
Junior Debentures 125 7.60 2038
Significant Factors
- -------------------
Nuclear Plant Outages
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 2003 and Unit 2 returned
to service in June 2003 following completion of a scheduled refueling outage.
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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The Federal EPA and a number of states
alleged I&M, certain affiliated companies 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 us 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 we do not prevail, any capital and operating costs of
additional pollution control equipment that may be required as well as any
penalties imposed would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity. See Note 5 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.
We are installing 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 of
approximately $39 million. The actual cost to comply could be significantly
different than the estimate 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 5 for further discussion.
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $70,861
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (19,968)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 164
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (4,861)
Changes in Fair Value of Risk Management
Contracts (d) (928)
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) (9,928)
--------
Total MTM Risk Management Contract Net
Assets 35,340
Net Non-Trading Related Derivative
Contracts 985
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $36,325
========
(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, 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.
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
our total MTM asset or liability (external sources or
modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(180) $32 $(164) $- $- $- $(312)
Prices Provided by Other External Sources -
OTC Broker Quotes (a) 812 9,067 3,827 3,356 795 - 17,857
Prices Based on Models and Other Valuation
Methods (b) 821 2,790 1,998 2,416 2,664 7,106 17,795
------- -------- ------- ------- ------- ------- --------
Total $1,453 $11,889 $5,661 $5,772 $3,459 $7,106 $35,340
======= ======== ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources" reflects information obtained
from over-the-counter brokers, industry services, or multiple-party
on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is 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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power
--------
(in thousands)
Accumulated OCI, December 31, 2002 $(286)
Changes in Fair Value (a) 526
Reclassifications from OCI to Net
Income (b) 295
------
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $535
======
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $933 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$494 $1,402 $646 $140 $927 $2,840 $1,016 $206
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- -------------------------------------------------------
Electric Generation, Transmission and Distribution $356,003 $353,897 $1,022,296 $982,565
Sales to AEP Affiliates 67,001 60,517 196,212 153,127
--------- --------- ----------- ----------
TOTAL 423,004 414,414 1,218,508 1,135,692
--------- --------- ----------- ----------
OPERATING EXPENSES
- -------------------------------------------------------
Fuel for Electric Generation 67,588 65,904 206,445 173,223
Purchased Electricity for Resale 9,058 6,706 22,375 17,386
Purchased Electricity from AEP Affiliates 68,653 59,846 207,904 176,463
Other Operation 109,106 108,457 319,019 340,556
Maintenance 38,518 41,668 112,480 112,291
Depreciation and Amortization 43,453 42,081 130,020 125,817
Taxes Other Than Income Taxes 15,698 16,698 44,668 52,794
Income Taxes 14,688 16,050 41,136 29,930
--------- --------- ----------- ----------
TOTAL 366,762 357,410 1,084,047 1,028,460
--------- --------- ----------- ----------
OPERATING INCOME 56,242 57,004 134,461 107,232
Nonoperating Income 19,335 17,899 36,240 56,452
Nonoperating Expenses 18,130 12,875 43,965 35,285
Nonoperating Income Tax Expense (Credit) 821 2,999 (4,479) 3,887
Interest Charges 19,510 23,717 64,603 70,648
--------- --------- ----------- ----------
Net Income Before Cumulative Effect of Accounting
Change 37,116 35,312 66,612 53,864
Cumulative Effect of Accounting Change
(Net of Tax) - - (3,160) -
--------- --------- ----------- ----------
NET INCOME 37,116 35,312 63,452 53,864
Preferred Stock Dividend Requirements
(Including Capital Stock Expense) 118 1,145 2,390 3,453
--------- --------- ----------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $36,998 $34,167 $61,062 $50,411
========= ========= =========== ==========
The common stock of I&M is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
AND COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
JANUARY 1, 2002 $56,584 $733,216 $74,605 $(3,835) $860,570
Capital Contributions from Parent Company 125,000 125,000
Preferred Stock Dividends (3,352) (3,352)
Capital Stock Expense 310 (100) 210
-----------
982,428
-----------
COMPREHENSIVE INCOME
- ------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Cash Flow Interest Rate Hedge 3,835 3,835
Unrealized Gain on Cash Flow Power Hedges 349 349
NET INCOME 53,864 53,864
-----------
TOTAL COMPREHENSIVE INCOME 58,048
-------- --------- --------- --------- -----------
SEPTEMBER 30, 2002 $56,584 $858,526 $125,017 $349 $1,040,476
======== ========= ========= ========= ===========
JANUARY 1, 2003 $56,584 $858,560 $143,996 $(40,487) $1,018,653
Common Stock Dividends (30,000) (30,000)
Preferred Stock Dividends (2,289) (2,289)
Capital Stock Expense 101 (101) -
-----------
986,364
-----------
COMPREHENSIVE INCOME
- ------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges 821 821
NET INCOME 63,452 63,452
-----------
TOTAL COMPREHENSIVE INCOME 64,273
-------- --------- --------- --------- -----------
SEPTEMBER 30, 2003 $56,584 $858,661 $175,058 $(39,666) $1,050,637
======== ========= ========= ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------------------
Production $2,872,210 $2,768,463
Transmission 992,046 971,599
Distribution 947,186 921,835
General (including nuclear fuel) 269,550 220,137
Construction Work in Progress 163,884 147,924
----------- -----------
TOTAL 5,244,876 5,029,958
Accumulated Depreciation and Amortization 2,719,346 2,568,604
----------- -----------
TOTAL - NET 2,525,530 2,461,354
----------- -----------
Nuclear Decommissioning and Spent Nuclear Fuel
Disposal Trust Funds 945,372 870,754
Long-term Risk Management Assets 51,574 83,265
Other Property and Investments 110,921 120,941
CURRENT ASSETS
- -------------------------------------------------------
Cash and Cash Equivalents 4,075 3,237
Advances to Affiliates - 191,226
Accounts Receivable:
Customers 55,735 67,333
Affiliated Companies 84,914 122,489
Miscellaneous 19,420 30,468
Allowance for Uncollectible Accounts (568) (578)
Fuel 25,014 32,731
Materials and Supplies 105,757 95,552
Risk Management Assets 36,271 68,148
Prepayments and Other 13,503 18,410
----------- -----------
TOTAL 344,121 629,016
----------- -----------
Regulatory Assets 265,205 348,212
Deferred Charges 51,709 73,649
TOTAL ASSETS $4,294,432 $4,587,191
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- -------------------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $56,584 $56,584
Paid-in Capital 858,661 858,560
Accumulated Other Comprehensive Income (Loss) (39,666) (40,487)
Retained Earnings 175,058 143,996
----------- -----------
Total Common Shareholder's Equity 1,050,637 1,018,653
Cumulative Preferred Stock - Not Subject to Mandatory Redemption 8,101 8,101
Liability for Cumulative Preferred Stock - Subject to Mandatory
Redemption 63,445 64,945
Long-term Debt 1,188,337 1,587,062
----------- -----------
TOTAL 2,310,520 2,678,761
----------- -----------
OTHER NONCURRENT LIABILITIES
- -------------------------------------------------------
Asset Retirement Obligations 543,688 -
Nuclear Decommissioning - 620,672
Other 128,957 138,965
----------- -----------
TOTAL 672,645 759,637
----------- -----------
CURRENT LIABILITIES
- -------------------------------------------------------
Long-term Debt Due Within One Year 180,000 30,000
Advances from Affiliates 13,929 -
Accounts Payable:
General 81,366 125,048
Affiliated Companies 41,666 93,608
Taxes Accrued 43,415 71,559
Interest Accrued 23,674 21,481
Risk Management Liabilities 23,541 48,568
Other 111,791 101,051
----------- -----------
TOTAL 519,382 491,315
----------- -----------
Deferred Income Taxes 316,515 356,197
Deferred Investment Tax Credits 92,205 97,709
Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 71,105 73,885
Long-term Risk Management Liabilities 27,979 32,261
Deferred Credits and Regulatory Liabilities 284,081 97,426
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $4,294,432 $4,587,191
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- -------------------------------------------------------
Net Income $63,452 $53,864
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change 3,160 -
Depreciation and Amortization 130,020 125,881
Deferral of Incremental Nuclear Refueling Outage Expenses, Net (4,049) (38,103)
Unrecovered Fuel and Purchased Power Costs 28,126 28,126
Amortization of Nuclear Outage Costs 30,000 30,000
Deferred Income Taxes (17,767) (6,885)
Deferred Investment Tax Credits (5,504) (5,534)
Mark-to-Market of Risk Management Contracts 30,661 (20,358)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 60,211 (115,027)
Fuel, Materials and Supplies (2,488) 1,155
Accounts Payable (95,624) 79,400
Taxes Accrued (28,144) 14,734
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets (15,379) (31,715)
Change in Other Liabilities (4,121) 27,458
--------- ---------
Net Cash Flows From Operating Activities 191,018 161,460
--------- ---------
INVESTING ACTIVITIES
- -------------------------------------------------------
Construction Expenditures (108,201) (92,387)
Other 1,655 1,027
--------- ---------
Net Cash Flows Used For Investing Activities (106,546) (91,360)
--------- ---------
FINANCING ACTIVITIES
- -------------------------------------------------------
Capital Contributions from Parent - 125,000
Issuance of Long-term Debt - 49,648
Retirement of Cumulative Preferred Stock (1,500) (424)
Retirement of Long-term Debt (255,000) (250,000)
Change in Advances to/from Affiliates, Net 205,155 1,214
Dividends Paid on Common Stock (30,000) -
Dividends Paid on Cumulative Preferred Stock (2,289) (3,340)
--------- ---------
Net Cash Flows Used For Financing Activities (83,634) (77,902)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 838 (7,802)
Cash and Cash Equivalents at Beginning of Period 3,237 16,804
--------- ---------
Cash and Cash Equivalents at End of Period $4,075 $ 9,002
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $59,359,000 and
$63,987,000 and for income taxes was $79,880,000 and $21,225,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income for the third quarter of 2003 increased $0.5 million from the
corresponding quarter in 2002 due to improved earnings from system sales and
transmission revenues. Net Income for the nine months ended September 30, 2003
decreased $1 million from the prior year due to the loss from the Cumulative
Effect of Accounting Change of $1 million (see Note 2). Income Before Cumulative
Effect of Accounting Change for the first nine months of 2003 was essentially
flat compared to the prior year period as improved earnings from system sales
and transmission revenues were offset by decreased net nonoperating income. As a
member of the AEP Power Pool, we share in the revenues and costs of marketing
and activities conducted on our behalf by the AEP Power Pool.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income for the third quarter of 2003 increased $2 million primarily
due to:
o Increases in system sales and transmission revenues of $5
million and an increase in gains from risk management activities
of $3 million.
o A decrease in Income Taxes of $2 million primarily due to state income
tax accrual adjustments.
The increases in Operating Income were partially offset by:
o A decline in retail sales of $2 million in the third quarter of
2003 resulting from decreased residential sales reflecting the
mild weather conditions, despite a rate increase to recover the
cost of emission control equipment (see Note 3). Cooling degree
days were down 32% for the third quarter of 2003 compared to the
prior year quarter. Lower industrial sales reflecting the
continued weak economy also contributed to the decline in retail
sales.
o An increase in purchased power of $4 million necessary to support
system sales.
o An increase in Depreciation and Amortization of $2 million
reflecting the completion and implementation of new capital
projects in the third quarter of 2003, as well as the
implementation of the SCR technology at the Big Sandy plant in the
second quarter of 2003.
Other Impacts on Earnings
Nonoperating Income for the third quarter of 2003 was relatively flat.
Nonoperating Income Tax Expense for the quarter increased $1 million for the
third quarter of 2003 primarily due to changes in certain book versus tax
differences accounted for on a flow-through basis.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income for the nine months ended September 30, 2003 increased $8
million primarily due to:
o An increase in system sales and transmission revenues of $12
million and an increase in gains from risk management activities of
$8 million.
o A decrease in Other Operation expense of $2 million from 2002 due to
decreased engineering expenses and lower employee benefit expenses.
The increases in Operating Income were partially offset by:
o A decline in industrial sales of $4 million reflecting the continued
weak economy.
o An increase in Depreciation and Amortization of $4 million
reflecting the depreciation on the capital projects implemented in
2003 as discussed above, as well as the implementation of an
enterprise-wide software application in mid-2002.
o Increases in Purchased Electricity from AEP Affiliates of $16
million necessary to support sales during the Big Sandy plant
shutdown for the NOx reduction upgrades. The outage resulted in a
decrease in net generation leading to a $6 million decrease in
fuel expense that partly offset the increased purchased power
expense. In addition, energy purchases increased from the Rockport
Plant based on plant availability, as required by the unit power
agreement with AEGCo, an affiliated company. The unit power
agreement with AEGCo provides for our purchase of 15% of the total
output of the two unit 2,600-MW capacity Rockport Plant.
Other Impacts on Earnings
Nonoperating Income for the first nine months of 2003 decreased $9 million
primarily due to reduced gains from risk management activities compared to the
prior year. Nonoperating Income Tax Expense for the first nine months of 2003
decreased $2 million primarily due to a decrease in pre-tax nonoperating book
income.
Cumulative Effect of Accounting Change
The Cumulative Effect of Accounting Change of $1 million is due to the
implementation of EITF 02-3 (see Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds Baa1 BBB BBB+
Senior Unsecured Debt Baa2 BBB BBB
In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Senior Unsecured Notes $75 5.625 2032
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Junior Debentures $40 8.72 2025
Intercompany Retirements of Debt Due to AEP
-------------------------------------------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Notes Payable $15 4.336 2003
Significant Factors
- -------------------
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 Kentucky where our generating plant is
located. The compliance date for the rules is May 31, 2004.
In May 2003, selective catalytic reduction (SCR) technology and other
combustion control technology to reduce NOx emissions at our Big Sandy plant
commenced operation to comply with these rules.
The capital expenditures for the SCR and other combustion control technology
totaled $179 million through September 30, 2003. In 2003, the KPSC granted
recovery of approximately $18 million annually (see Note 3). See Note 5 for
further discussion of emissions control technology.
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 transmission
system to RTOs. Further, legislation in certain states in which AEP subsidiaries
operate 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, we filed with KPSC for approval of our plan to transfer
functional control of our 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.
We are 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 (see Note 3).
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $24,998
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (7,926)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 60
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (1,744)
Changes in Fair Value of Risk Management
Contracts (d) 601
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (e) (2,685)
--------
Total MTM Risk Management Contract Net Assets 13,304
Net Non-Trading Related Derivative
Contracts 361
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $13,665
========
(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,
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 Statements of Income. These
net gains (losses) are recorded as regulatory liabilities/assets
for those subsidiaries that operate in regulated jurisdictions.
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
our total MTM asset or liability (external sources or
modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(66) $12 $(60) $- $- $- $(114)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 288 3,322 1,411 1,237 293 - 6,551
Prices Based on Models and Other
Valuation Methods (b) 480 1,160 736 890 982 2,619 6,867
----- ------- ------- ------- ------- ------- --------
Total $702 $4,494 $2,087 $2,127 $1,275 $2,619 $13,304
===== ======= ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power Interest Rate Consolidated
-------- ------------- ------------
(in thousands)
Accumulated OCI, December 31, 2002 $(103) $425 $322
Changes in Fair Value (a) 192 - 192
Reclassifications from OCI to Net
Income (b) 108 (65) 43
------ ----- -----
Accumulated OCI Derivative Gain (Loss) September
30, 2003 $197 $360 $557
====== ===== =====
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $430 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$182 $517 $238 $51 $333 $1,019 $364 $74
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- --------------------------------------------------------
Electric Generation, Transmission and Distribution $93,500 $87,720 $281,755 $264,154
Sales to AEP Affiliates 10,193 10,091 29,496 25,006
-------- -------- --------- ---------
TOTAL 103,693 97,811 311,251 289,160
-------- -------- --------- ---------
OPERATING EXPENSES
- --------------------------------------------------------
Fuel for Electric Generation 19,608 19,747 52,994 59,084
Purchased Electricity for Resale 738 24 719 26
Purchased Electricity from AEP Affiliates 34,723 31,440 108,289 92,747
Other Operation 12,519 12,932 36,351 37,902
Maintenance 6,671 7,168 20,597 19,795
Depreciation and Amortization 10,693 8,330 28,653 24,856
Taxes Other Than Income Taxes 2,300 1,904 6,742 6,407
Income Taxes 3,344 5,147 13,011 12,190
-------- -------- --------- ---------
TOTAL 90,596 86,692 267,356 253,007
-------- -------- --------- ---------
OPERATING INCOME 13,097 11,119 43,895 36,153
Nonoperating Income (Loss) 1,329 1,712 (1,636) 6,907
Nonoperating Expenses 212 707 554 701
Nonoperating Income Tax Expense (Credit) 370 (801) (1,114) 929
Interest Charges 7,343 6,931 21,202 19,944
-------- -------- --------- ---------
Income Before Cumulative Effect
of Accounting Change 6,501 5,994 21,617 21,486
Cumulative Effect of Accounting Change
(Net of Tax) - - (1,134) -
-------- -------- --------- ---------
NET INCOME $6,501 $5,994 $20,483 $21,486
======== ======== ========= =========
The common stock of KPCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
AND COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ -------- -------- ----------------- -----
JANUARY 1, 2002 $50,450 $158,750 $48,833 $(1,903) $256,130
Common Stock Dividends (21,132) (21,132)
---------
TOTAL 234,998
---------
COMPREHENSIVE INCOME
- ------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 1,519 1,519
NET INCOME 21,486 21,486
---------
TOTAL COMPREHENSIVE INCOME 23,005
-------- --------- -------- -------- ---------
SEPTEMBER 30, 2002 $50,450 $158,750 $49,187 $(384) $258,003
======== ========= ======== ======== =========
JANUARY 1, 2003 $50,450 $208,750 $48,269 $(9,451) $298,018
Common Stock Dividends (16,448) (16,448)
---------
TOTAL 281,570
---------
COMPREHENSIVE INCOME
- ------------------------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 235 235
NET INCOME 20,483 20,483
---------
TOTAL COMPREHENSIVE INCOME 20,718
-------- --------- -------- -------- ---------
SEPTEMBER 30, 2003 $50,450 $208,750 $52,304 $(9,216) $302,288
======== ========= ======== ======== =========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------------
Production $457,231 $275,121
Transmission 380,112 373,639
Distribution 422,127 414,281
General 67,071 67,449
Construction Work in Progress 17,067 165,129
----------- -----------
TOTAL 1,343,608 1,295,619
Accumulated Depreciation and Amortization 401,887 397,304
----------- -----------
TOTAL - NET 941,721 898,315
----------- -----------
Other Property and Investments 6,684 6,904
Long-term Risk Management Assets 19,006 29,871
CURRENT ASSETS
- --------------------------------------------------------
Cash and Cash Equivalents 760 2,304
Accounts Receivable:
Customers 17,395 22,044
Affiliated Companies 14,281 23,802
Miscellaneous 4,637 2,889
Allowance for Uncollectible Accounts (757) (192)
Fuel 9,702 10,817
Materials and Supplies 17,855 16,127
Accrued Utility Revenues 4,963 5,301
Accrued Tax Benefit - 1,253
Risk Management Assets 13,196 24,320
Prepayments and Other 2,825 2,127
----------- -----------
TOTAL 84,857 110,792
----------- -----------
Regulatory Assets 105,039 101,976
Deferred Charges 14,110 16,818
TOTAL ASSETS $1,171,417 $1,164,676
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
CAPATALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- --------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $50,450 $50,450
Paid-in Capital 208,750 208,750
Accumulated Other Comprehensive Income (Loss) (9,216) (9,451)
Retained Earnings 52,304 48,269
----------- -----------
Total Common Shareholder's Equity 302,288 298,018
----------- -----------
Long-term Debt:
Nonaffiliated 427,578 391,632
Affiliated 60,000 60,000
----------- -----------
Total Long-term Debt 487,578 451,632
----------- -----------
TOTAL 789,866 749,650
----------- -----------
Other Noncurrent Liabilities 25,228 27,319
CURRENT LIABILITIES
- --------------------------------------------------------
Long-term Debt Due Within One Year - Affiliated - 15,000
Advances from Affiliates 42,195 23,386
Accounts Payable:
General 28,019 46,515
Affiliated Companies 22,911 44,035
Customer Deposits 9,452 8,048
Interest Accrued 8,949 6,471
Taxes Accrued 202 -
Risk Management Liabilities 8,256 17,803
Other 11,353 14,322
----------- -----------
TOTAL 131,337 175,580
----------- -----------
Deferred Income Taxes 197,121 178,313
Deferred Investment Tax Credits 8,284 9,165
Long-term Risk Management Liabilities 10,281 11,488
Regulatory Liabilities and Deferred Credits 9,300 13,161
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,171,417 $1,164,676
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------
Net Income $20,483 $21,486
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Change 1,134 -
Depreciation and Amortization 28,653 24,856
Deferred Income Taxes 16,020 7,461
Deferred Investment Tax Credits (880) (886)
Deferred Fuel Costs, Net (772) 2,081
Mark-to-Market of Risk Management Contracts 9,950 (13,161)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 12,987 (13,559)
Fuel, Materials and Supplies (613) 484
Accrued Utility Revenues 338 (1,382)
Accounts Payable (39,620) 20,715
Taxes Accrued 1,455 (3,360)
Change in Other Assets (2,792) (2,154)
Change in Other Liabilities (61) 12,238
-------- ---------
Net Cash Flows From Operating Activities 46,282 54,819
-------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------
Construction Expenditures (71,154) (100,677)
Proceeds from Sales of Property and Other 967 182
-------- ---------
Net Cash Flow Used for Investing Activities (70,187) (100,495)
-------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------
Issuance of Long-term Debt - Nonaffiliated 75,000 -
Issuance of Long-term Debt - Affiliated - 123,843
Retirement of Long-term Debt - Nonaffiliated (40,000) (84,500)
Retirement of Long-term Debt - Affiliated (15,000) -
Change in Advances to/from Affiliates, Net 18,809 26,391
Dividends Paid (16,448) (21,132)
-------- ---------
Net Cash Flows From Financing Activities 22,361 44,602
-------- ---------
Net Decrease in Cash and Cash Equivalents (1,544) (1,074)
Cash and Cash Equivalents at Beginning of Period 2,304 1,947
-------- ---------
Cash and Cash Equivalents at End of Period $760 $873
======== =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $17,925,000 and
$19,560,000 in 2003 and 2002, respectively. Cash (received) paid for income
taxes was $(7,605,000) and $7,025,000 in 2003 and 2002, respectively. There were
no noncash acquisitions under capital lease in 2003. Noncash acquisitions under
capital leases in 2002 were $22,000.
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the
implementation of FIN 46. See Note 2, "New Accounting Pronouncements and
Cumulative Effect of Accounting Changes," and Note 8, "Leases," for further
discussion of the effects of FIN 46.
Results of Operations
- ---------------------
Net Income for the quarter decreased $10 million due primarily to mild summer
weather and increased interest charges related to new issuances of debt. Net
Income increased $120 million year-to-date including $125 million Cumulative
Effect of Accounting Changes in the first quarter of 2003 (see Note 2). Net
Income Before Cumulative Effect of Accounting Changes decreased $5 million
year-to-date primarily due to decreased revenues from risk management
activities. We, as a member of the AEP Power Pool, share in the revenues and the
costs of the AEP Power Pool's wholesale sales to neighboring utilities and risk
management transactions.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income decreased $3 million for the third quarter primarily due to the
following:
o Retail revenues decreased $10 million due primarily to milder
weather during the third quarter 2003 and economic pressures on
industrial customers. Cooling degree days were 36% less in the
third quarter this year compared with the third quarter of last
year. Industrial revenues dropped 5% from the third quarter of
last year.
o Risk management income decreased $13 million due primarily to
unfavorable market conditions and reduced activity.
o Third quarter Fuel for Electric Generation expense increased $7
million due primarily to an increase of 10% in MWHs generated, which
was sold to the AEP Power Pool.
o Maintenance expense increased $7 million due primarily to boiler
overhaul work coupled with increased expense in maintaining
overhead lines.
The decrease in Operating Income was partially offset by the following:
o Affiliated sales increased $34 million. The increase is the result
of optimizing our generation capacity and selling our excess
generated power to the AEP Power Pool.
o Income Taxes decreased $7 million primarily due to a decrease in
pre-tax operating book income offset in part by changes in certain
book versus tax differences accounted for on a flow-through basis.
Other Impacts of Earnings
Nonoperating Income increased $9 million for the third quarter due primarily to
the reduction in accruals for costs associated with coal companies sold prior to
2003.
Interest charges increased $15 million for the third quarter due primarily to
the replacement of lower cost floating-rate short-term debt with higher cost
fixed-rate longer-term debt.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September
- ----------------------------------------------------------------------------
30, 2002
- --------
Operating Income
Operating Income increased $31 million year to date primarily due to the
following:
o Revenues from non-affiliated system sales increased $25 million
and affiliated sales increased $90 million. The increase in
non-affiliated system sales is the result of the increase in
volume of AEP Power Pool Sales allocated to us for the first nine
months of 2003. The increase in affiliated sales is the result of
optimizing our generation capacity and selling our excess
generated power to the AEP Power Pool.
o Other Operation expenses decreased due primarily to a $7 million
pre-tax adjustment to the workers' compensation reserve for coal
companies sold in July 2001 and a $4 million decrease primarily
due to a decrease in OPCo's portion of the total AEP Transmission
Equalization payments.
The increase in Operating Income was partially offset by the following:
o Year-to-date Fuel for Electric Generation expense increased $22
million due primarily to an increase of 8.5% in MWHs generated.
o Maintenance expense increased $37 million due primarily to boiler
overhaul work coupled with increased expense in maintaining
overhead lines due to storm damage in southern Ohio.
o Purchased Electricity from AEP Affiliates increased $16 million as
a result of an increased volume of purchases from the
AEP Power Pool for the first nine months of 2003.
Other Impacts on Earnings
Nonoperating Income decreased $22 million year-to-date due primarily to lower
margins for risk management activities outside of AEP's traditional marketing
area reflecting reduced demand and AEP's plan to exit risk management activities
in areas outside of its traditional market area.
Interest charges increased $14 million due primarily to the replacement of lower
cost floating-rate short-term debt with higher cost fixed-rate longer-term debt.
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes is due to the one-time after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A-
Senior Unsecured Debt A3 BBB BBB+
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.
Cash Flow
Cash flows for nine months ended September 30, 2003 and 2002 were as follows:
2003 2002
---- ----
(in thousands)
Cash and cash equivalents at beginning of period $5,285 $8,848
Cash flow from (used for):
Operating activities 232,482 446,138
Investing activities (160,244) (218,813)
Financing activities (70,810) (228,221)
--------- ---------
Net increase (decrease) in cash and cash equivalents 1,428 (896)
--------- ---------
Cash and cash equivalents at end of period $6,713 $7,952
========= =========
Operating Activities
Cash flow from operating activities for the nine months ended September 30, 2003
decreased $214 million as they were adversely impacted primarily by significant
reductions of accounts payable balances partially associated with a wind down of
risk management activities in the current year.
Investing Activities
Cash flows used for investing activities were reduced in the current year due
primarily to a $60 million decrease in construction expenditures.
Financing Activities
Cash flow used for financing activities for the first nine months of 2003 used
$157 million less than the first nine months of 2002 primarily due to:
o Retirement and restructuring of our long-term and short-term debt
during 2003. We retired $300 million of Long-term Debt to
Affiliated Companies and $275 million of Short-term Debt to
Affiliated Companies with the proceeds of two Senior Unsecured
Notes at $250 million each.
o We issued two series of Senior Unsecured Notes, each in the amount of
$225 million each in July 2003.
o The change in Advances to/from Affiliates, net decreased $133 million
from prior period.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Senior Unsecured Notes $250 5.50 2013
Senior Unsecured Notes 250 6.60 2033
Senior Unsecured Notes 225 4.85 2014
Senior Unsecured Notes 225 6.375 2033
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
First Mortgage Bonds $30 6.75 2003
Intercompany Retirements of Debt Due to AEP
-------------------------------------------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- ----
(in millions) (%)
Notes Payable $240 6.501 2006
Notes Payable 60 4.336 2003
Significant Factors
- -------------------
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), we are involved in litigation regarding generating
plant emissions under the Clean Air Act. The Federal EPA and a number of states
alleged OPCo, certain affiliated companies 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 AEP
subsidiaries in U.S. District Court for the Southern District of Ohio. A
separate lawsuit initiated by certain special interest groups was consolidated
with the Federal EPA case. The alleged modification of the generating units
occurred over a 20 year period.
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
5 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.
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 $531 million to $860 million. 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, these costs would adversely affect future results of
operations, cash flows and possibly financial condition. See Note 5 for further
discussion.
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
--------------
Beginning Balance December 31, 2002 $94,106
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (36,790)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) 199
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission (4,159)
Changes in Fair Value of Risk Management
Contracts (d) (3,694)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e) -
--------
Total MTM Risk Management Contract Net Assets 49,662
Net Non-Trading Related Derivative
Contracts 1,207
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $50,869
========
(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
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in regulated
jurisdictions.
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
our total MTM asset or liability (external sources or modeled
internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in thousands)
Prices Actively Quoted - Exchange
Traded Contracts $(219) $40 $(200) $- $- $- $(379)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) 4,218 13,368 4,668 4,093 969 - 27,316
Prices Based on Models and Other
Valuation Methods (b) 1,588 3,839 2,437 2,946 3,249 8,666 22,725
------- -------- ------- ------- ------- ------- --------
Total $5,587 $17,247 $6,905 $7,039 $4,218 $8,666 $49,662
======= ======== ======= ======= ======= ======= ========
(a)"Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers, industry
services, or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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 foreign
currency risk management activities and other hedging activities. In accordance
with GAAP, all amounts are presented net of related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic Foreign
Power Currency Consolidated
-------- -------- ------------
(in thousands)
Accumulated OCI, December 31, 2002 $(354) $(384) $(738)
Changes in Fair Value (a) 645 - 645
Reclassifications from OCI to Net
Income (b) 361 10 371
------ ------ ------
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $652 $(374) $278
====== ====== ======
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $1,125 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
------------------ -----------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$602 $1,710 $788 $170 $1,150 $3,521 $1,259 $255
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
OPERATING REVENUES
- ----------------------------------------------
Electric Generation, Transmission and Distribution $418,083 $444,298 $1,256,862 $1,251,288
Sales to AEP Affiliates 147,235 113,276 438,473 348,303
--------- --------- ----------- -----------
TOTAL 565,318 557,574 1,695,335 1,599,591
--------- --------- ----------- -----------
OPERATING EXPENSES
- ----------------------------------------------
Fuel for Electric Generation 155,222 148,480 462,316 439,913
Purchased Electricity for Resale 15,219 15,841 52,064 49,042
Purchased Electricity from AEP Affiliates 23,693 20,375 70,905 54,867
Other Operation 92,376 94,893 269,998 290,982
Maintenance 38,598 32,011 127,466 90,956
Depreciation and Amortization 67,365 62,144 189,140 185,941
Taxes Other Than Income Taxes 45,582 46,341 132,350 135,472
Income Taxes 33,465 40,279 118,597 110,446
--------- --------- ----------- -----------
TOTAL 471,520 460,364 1,422,836 1,357,619
--------- --------- ----------- -----------
OPERATING INCOME 93,798 97,210 272,499 241,972
Nonoperating Income 20,567 11,157 21,350 43,057
Nonoperating Expenses 8,840 6,241 26,565 17,501
Nonoperating Income Tax Expense (Credit) 1,646 3,638 (1,446) 7,986
Interest Charges 33,512 18,230 73,736 59,885
--------- --------- ----------- -----------
Income Before Cumulative Effect of
Accounting Changes 70,367 80,258 194,994 199,657
Cumulative Effect of Accounting Changes
(Net of Tax) - - 124,632 -
--------- --------- ----------- -----------
NET INCOME 70,367 80,258 319,626 199,657
Preferred Stock Dividend Requirements 286 315 915 944
--------- --------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $70,081 $79,943 $318,711 $198,713
========= ========= =========== ===========
The common stock of OPCo is wholly-owned by AEP.
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------ ------- -------- ----------------- -----
JANUARY 1, 2002 $321,201 $462,483 $401,297 $(196) $1,184,785
Common Stock Dividends (97,746) (97,746)
Preferred Stock Dividends (944) (944)
-----------
1,086,095
-----------
COMPREHENSIVE INCOME
- ----------------------------------------------
Other Comprehensive Income (Loss)
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 242 242
NET INCOME 199,657 199,657
-----------
TOTAL COMPREHENSIVE INCOME 199,899
--------- --------- --------- --------- -----------
SEPTEMBER 30, 2002 $321,201 $462,483 $502,264 $46 $1,285,994
========= ========= ========= ========= ===========
JANUARY 1, 2003 $321,201 $462,483 $522,316 $(72,886) $1,233,114
Common Stock Dividends (125,800) (125,800)
Preferred Stock Dividends (915) (915)
Capital Stock Expense 1 1
-----------
TOTAL 1,106,400
-----------
COMPREHENSIVE INCOME
- ----------------------------------------------
Other Comprehensive Income (Loss)
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 1,016 1,016
Minimum Pension Liability 5,625 5,625
NET INCOME 319,626 319,626
-----------
TOTAL COMPREHENSIVE INCOME 326,267
--------- --------- --------- --------- -----------
SEPTEMBER 30, 2003 $321,201 $462,484 $715,227 $(66,245) $1,432,667
========= ========= ========= ========= ===========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
ELECTRIC UTILITY PLANT
- ----------------------------------------------
Production $4,013,884 $3,116,825
Transmission 928,373 905,829
Distribution 1,146,589 1,114,600
General 239,523 260,153
Construction Work in Progress 136,462 288,419
------------ -----------
Total 6,464,831 5,685,826
Accumulated Depreciation and Amortization 2,548,845 2,566,828
------------ -----------
TOTAL - NET 3,915,986 3,118,998
------------ -----------
Other Property and Investments 52,907 61,686
Long-term Risk Management Assets 62,885 103,230
CURRENT ASSETS
- ----------------------------------------------
Cash and Cash Equivalents 6,713 5,285
Advances to Affiliates 142,894 -
Accounts Receivable:
Customers 78,341 95,100
Affiliated Companies 92,972 124,244
Miscellaneous 21,381 19,281
Allowance for Uncollectible Accounts (887) (909)
Fuel 81,926 87,409
Materials and Supplies 86,347 85,379
Risk Management Assets 49,332 92,108
Prepayments and Other 26,198 12,083
------------ -----------
TOTAL 585,217 519,980
------------ -----------
Regulatory Assets 512,890 568,641
Deferred Charges and Other Assets 49,571 84,497
TOTAL $5,179,456 $4,457,032
============ ===========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
CAPITALIZATION
- ----------------------------------------------
Common Shareholder's Equity:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $321,201 $321,201
Paid-in Capital 462,484 462,483
Accumulated Other Comprehensive Income (Loss) (66,245) (72,886)
Retained Earnings 715,227 522,316
----------- -----------
Total Common Shareholder's Equity 1,432,667 1,233,114
----------- -----------
Cumulative Preferred Stock Not Subject to Mandatory Redemption 16,645 16,648
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption 8,350 8,850
Long-term Debt:
Nonaffiliated 1,819,176 677,649
Affiliated - 240,000
----------- -----------
Total Long-term Debt 1,819,176 917,649
----------- -----------
TOTAL CAPITALIZATION 3,276,838 2,176,261
----------- -----------
Minority Interest 16,918 -
Other Noncurrent Liabilities 209,808 227,689
CURRENT LIABILITIES
- ----------------------------------------------
Long-term Debt Due Within One Year - Nonaffiliated 268,919 89,665
Long-term Debt Due Within One Year - Affiliated - 60,000
Short-term Debt - General 28,651 -
Short-term Debt - Affiliates - 275,000
Advances from Affiliates - 129,979
Accounts Payable - General 97,323 170,563
Accounts Payable - Affiliated Companies 67,516 145,718
Customer Deposits 16,548 12,969
Taxes Accrued 94,096 111,778
Interest Accrued 33,661 18,809
Obligations Under Capital Leases 9,509 14,360
Risk Management Liabilities 27,332 61,839
Other 69,846 80,608
----------- -----------
TOTAL 713,401 1,171,288
----------- -----------
Deferred Income Taxes 886,015 794,387
Deferred Investment Tax Credits 16,460 18,748
Long-term Risk Management Liabilities 34,016 39,702
Deferred Credits 26,000 28,957
Commitments and Contingencies (Note 5)
TOTAL $5,179,456 $4,457,032
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in thousands)
OPERATING ACTIVITIES
- ----------------------------------------------
Net Income $319,626 $199,657
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Cumulative Effect of Accounting Changes (124,632) -
Depreciation and Amortization 189,140 185,941
Deferred Income Taxes 4,139 95
Mark-to-Market of Risk Management Contracts 40,283 (34,477)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net 45,966 14,289
Fuel, Materials and Supplies 4,515 10,333
Accrued Utility Revenues (8,167) (2,677)
Prepayments and Other (9,030) (11,330)
Accounts Payable (215,012) 20,011
Customer Deposits 3,579 9,101
Taxes Accrued (17,682) 37,370
Interest Accrued 9,516 1,870
Deferred Property Taxes 46,491 45,275
Change in Other Assets (10,895) (18,513)
Change in Other Liabilities (45,355) (10,807)
--------- ---------
Net Cash Flows From Operating Activities 232,482 446,138
--------- ---------
INVESTING ACTIVITIES
- ----------------------------------------------
Construction Expenditures (163,864) (224,257)
Proceeds from Sale of Property and Other 3,620 5,444
--------- ---------
Net Cash Flows Used For Investing Activities (160,244) (218,813)
--------- ---------
FINANCING ACTIVITIES
- ----------------------------------------------
Issuance of Long-term Debt 950,000 -
Capital Contribution from Parent (17,910) -
Change in Advances to/from Affiliates, Net (272,872) (139,531)
Change in Short-term Debt 2,039 -
Change in Short-term Debt - Affiliates (275,000) 150,000
Retirement of Long-term Debt - Nonaffiliated (29,850) (140,000)
Retirement of Long-term Debt - Affiliated (300,000) -
Retirement of Cumulative Preferred Stock (502) -
Dividends Paid on Common Stock (125,800) (97,746)
Dividends Paid on Cumulative Preferred Stock (915) (944)
--------- ---------
Net Cash Flows Used For Financing Activities (70,810) (228,221)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 1,428 (896)
Cash and Cash Equivalents at Beginning of Period 5,285 8,848
--------- ---------
Cash and Cash Equivalents at End of Period $6,713 $7,952
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $57,517,000 and
$56,864,000 and for income taxes was $74,858,000 and $29,981,000 in 2003 and
2002, respectively. Noncash acquisitions under capital leases were $98,000 in
2002.
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
--------------------------------------------------------
Results of Operations
- ---------------------
Net Income increased $6 million year-to-date but decreased $3 million for the
third quarter. The increase for the year was due mainly to higher retail base
revenue and wholesale margins, while for the quarter a rise in Operating
Expenses offset these increases. Significant fluctuations occurred in Revenues,
Fuel and Purchased Electricity due to certain ICR adjustments in 2002 and
changing natural gas prices; however, operating income was not significantly
affected due to the functioning of the fuel adjustment clause in Oklahoma.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income decreased $7 million primarily due to the following:
o A $2 million reduction resulting from the absence of the reversal of a
Provision for Rate Refund that was recorded in 2002.
o Decreased transmission revenues of $2 million.
o Increased Other Operation and Maintenance expenses of $5 million due in
large part to increased tree trimming and postretirement benefits
expenses.
The decrease in Operating Income was partially offset by:
o Increased wholesale margins of $3 million due to an increase in our
percentage of margins earned from system risk management activities.
o Increased retail base revenue of $5 million due in large part to an
increase in industrial revenues. The number of cooling degree-days
decreased 2%.
Other Impacts on Earnings
Nonoperating Income increased $6 million primarily due to a gain on the
disposition of excess land.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
- ------------------------------------------------------------------
September 30, 2002
- ------------------
Operating Income
Operating Income increased $6 million primarily due to:
o Increased wholesale margins of $7 million due to an increase in our
percentage of margins earned from system risk management activities.
o Increased retail base revenue of $5 million, resulting mainly from
increased KWH sales of 3%. Cooling degree-days decreased 5% while
heating degree-days increased 14%.
.
The increase in Operating Income was partially offset by:
o Increased Other Operation expense of $4 million due mainly to employee
related expenses consisting largely of increased cost for postretirement
benefits.
o Increased Taxes Other Than Income Taxes of $2 million due primarily to
increased property value assessments and franchise taxes.
Other Impacts on Earnings
Nonoperating Income increased $5 million primarily due to a gain on the
disposition of excess land.
Interest Charges increased $5 million as a result of replacing floating rate
short-term debt with longer term fixed rate unsecured debt.
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
------- --- -----
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt Baa1 BBB A-
In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from A2 to Baa1 and secured debt from A1 to A3
The completion of this review was a culmination of ratings action started during
2002. In March 2003, S&P lowered AEP and our senior unsecured debt and first
mortgage bonds ratings from BBB+ to BBB.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- ------- ----
(in millions) (%)
Senior Unsecured Notes $150 4.85 2010
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- -----
(in millions) (%)
First Mortgage Bonds $ 35 6.25 2003
First Mortgage Bonds 65 7.25 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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
Beginning Balance December 31, 2002 $3,545
(Gain) Loss from Contracts Realized/Settled During
the Period (a) 220
Fair Value of New Contracts When Entered Into During
the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission -
Changes in Fair Value of Risk Management
Contracts (d) -
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (e)
9,564
--------
Total MTM Risk Management Contract Net
Assets 13,329
Net Non-Trading Related Derivative
Contracts 605
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $13,934
========
(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, 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.
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 our
total MTM asset or liability (external sources or modeled internally).
o The maturity, by year, of our net assets/liabilities, giving an indication
of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
----------- ------ ------ ------ ------ ------ -------
(in thousands)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) $287 $3,203 $1,415 $1,241 $294 $- $6,440
Prices Based on Models and Other
Valuation Methods (b) 481 1,164 739 893 985 2,627 6,889
----- ------- ------- ------- ------- ------- --------
Total $768 $4,367 $2,154 $2,134 $1,279 $2,627 $13,329
===== ======= ======= ======= ======= ======= ========
(a) "Prices Provided by Other External Sources - OTC Broker Quotes reflects
information obtained from over-the-counter brokers, industry services,
or multiple-party on-line platforms.
(b) "Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income(Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power
---------
(in thousands)
Accumulated OCI, December 31, 2002 $(42)
Changes in Fair Value (a) 259
Reclassifications from OCI to Net
Income (b) 176
------
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $ 393
======
(a) "Changes in Fair Value" shows 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.
(b) "Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $685 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
-------------------- -------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
--- ---- ------- --- --- ---- ------- ---
$363 $1,029 $474 $102 $136 $415 $148 $30
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
----- ----- ----- -----
(in thousands)
OPERATING REVENUES
- ---------------------------------------------------
Electric Generation, Transmission and Distribution $355,064 $236,724 $860,544 $535,784
Sales to AEP Affiliates 3,511 (6,626) 17,929 1,630
--------- --------- --------- ---------
TOTAL 358,575 230,098 878,473 537,414
--------- --------- --------- ---------
OPERATING EXPENSES
- ---------------------------------------------------
Fuel for Electric Generation 177,162 58,410 415,731 150,279
Purchased Electricity for Resale 11,524 (15,250) 30,878 (7,230)
Purchased Electricity from AEP Affiliates 24,132 38,320 94,515 67,238
Other Operation 33,765 31,957 97,067 92,845
Maintenance 12,763 10,024 34,523 36,079
Depreciation and Amortization 21,715 22,496 64,568 64,473
Taxes Other Than Income Taxes 9,526 9,278 27,611 25,209
Income Taxes 24,461 24,153 28,192 29,200
--------- --------- --------- ---------
TOTAL 315,048 179,388 793,085 458,093
--------- --------- --------- ---------
OPERATING INCOME 43,527 50,710 85,388 79,321
Nonoperating Income 6,691 1,022 7,413 2,351
Nonoperating Expense 304 2 467 666
Nonoperating Income Tax Expense 1,488 922 1,133 681
Interest Charges 10,336 9,806 34,493 29,351
--------- --------- --------- ---------
NET INCOME 38,090 41,002 56,708 50,974
Preferred Stock Dividend Requirements 53 53 159 159
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK
$38,037 $40,949 $56,549 $50,815
========= ========= ========= =========
The common stock of PSO is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Accumulated
Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------- ------- ---------- -------------- --------
JANUARY 1, 2002 $157,230 $180,016 $142,994 $- $480,240
Common Stock Dividends (67,368) (67,368)
Preferred Stock Dividends (159) (159)
---------
412,713
---------
COMPREHENSIVE INCOME
- -------------------------------
Other Comprehensive Income,
Net of Taxes:
Unrealized Gain on Cash Flow Hedges 45 45
NET INCOME 50,974 50,974
---------
TOTAL COMPREHENSIVE INCOME 51,019
--------- --------- --------- --------- ---------
SEPTEMBER 30, 2002 $157,230 $180,016 $126,441 $45 $463,732
========= ========= ========= ========= =========
JANUARY 1, 2003 $157,230 $180,016 $116,474 $(54,473) $399,247
Capital Contribution from Parent 50,000 50,000
Common Stock Dividends (15,000) (15,000)
Preferred Stock Dividends (159) (159)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
---------
TOTAL 433,540
---------
COMPREHENSIVE INCOME
- -------------------------------
Other Comprehensive Income (Loss),
Net of Taxes:
Minimum Pension Liability (59) (59)
Unrealized Gain on Cash Flow Hedges 435 435
NET INCOME 56,708 56,708
---------
TOTAL COMPREHENSIVE INCOME 57,084
--------- --------- --------- --------- ---------
SEPTEMBER 30, 2003 $157,230 $230,016 $157,475 $(54,097) $490,624
========= ========= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
------ ------
(in thousands)
ELECTRIC UTILITY PLANT
- --------------------------------------------------------
Production $1,064,055 $1,040,520
Transmission 447,286 432,846
Distribution 1,012,605 990,947
General 194,317 206,747
Construction Work in Progress 52,881 88,444
----------- -----------
TOTAL 2,771,144 2,759,504
Accumulated Depreciation and Amortization 1,253,819 1,239,855
----------- -----------
TOTAL - NET 1,517,325 1,519,649
----------- -----------
Other Property and Investments 7,147 5,383
Long-term Risk Management Assets 15,967 4,481
CURRENT ASSETS
- --------------------------------------------------------
Cash and Cash Equivalents 17,587 16,774
Advances to Affiliates 103,453 -
Accounts Receivable:
Customers 26,639 31,687
Affiliated Companies 25,160 14,139
Allowance for Uncollectible Accounts (47) (84)
Fuel Inventory 18,551 19,973
Materials and Supplies 37,444 37,375
Under-recovered Fuel Costs 43,608 76,470
Risk Management Assets 12,772 3,841
Prepayments and Other 3,633 2,735
----------- -----------
TOTAL 288,800 202,910
---------- -----------
Regulatory Assets 25,838 26,150
Deferred Charges 29,184 18,117
TOTAL ASSETS $1,884,261 $1,776,690
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
------ ------
(in thousands)
CAPITALIZATION
- ---------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $157,230 $157,230
Paid-in Capital 230,016 180,016
Accumulated Other Comprehensive Income (Loss) (54,097) (54,473)
Retained Earnings 157,475 116,474
----------- -----------
Total Common Shareholder's Equity 490,624 399,247
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,267 5,267
PSO - Obligated, Mandatorily Redeemable Preferred Securities of
Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO - 75,000
Long-term Debt 672,691 445,437
----------- -----------
TOTAL 1,168,582 924,951
----------- -----------
Other Noncurrent Liabilities 55,906 54,761
CURRENT LIABILITIES
- ----------------------------------------------------------------
Long-term Debt Due Within One Year - 100,000
Advances from Affiliates - 86,105
Accounts Payable:
General 52,350 61,169
Affiliated Companies 96,358 78,076
Customer Deposits 25,172 21,789
Taxes Accrued 19,196 6,854
Interest Accrued 7,648 6,979
Risk Management Liabilities 7,873 3,260
Other 20,484 24,957
----------- -----------
TOTAL 229,081 389,189
----------- -----------
Deferred Income Taxes 350,295 341,396
Deferred Investment Tax Credits 30,858 32,201
Regulatory Liabilities and Deferred Credits 42,607 32,611
Long-Term Risk Management Liabilities 6,932 1,581
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $1,884,261 $1,776,690
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
------ ------
(in thousands)
OPERATING ACTIVITIES
- -----------------------------------------------------
Net Income $56,708 $50,974
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 64,568 64,473
Deferred Income Taxes 6,536 33,841
Deferred Investment Tax Credits (1,343) (1,343)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (6,010) (27,994)
Fuel, Materials and Supplies 1,353 426
Accounts Payable 9,463 35,739
Taxes Accrued 12,342 11,124
Fuel Recovery 32,862 (108,565)
Deferred Property Taxes (8,239) (8,092)
Changes in Other Assets (6,165) (103)
Changes in Other Liabilities 54 (31,825)
--------- ---------
Net Cash Flows From Operating Activities 162,129 18,655
--------- ---------
INVESTING ACTIVITIES
- -----------------------------------------------------
Construction Expenditures (59,263) (51,629)
Proceeds from Sale of Property 2,664 963
--------- ---------
Net Cash Flows Used For Investing Activities (56,599) (50,666)
--------- ---------
FINANCING ACTIVITIES
- -----------------------------------------------------
Capital Contributions from Parent 50,000 -
Issuance of Long-term Debt 150,000 -
Change in Advances to/from Affiliates, Net (189,558) 105,551
Retirement of Long-term Debt (100,000) -
Dividends Paid on Common Stock (15,000) (67,368)
Dividends Paid on Cumulative Preferred Stock (159) (159)
--------- ---------
Net Cash Flows From (Used For) Financing Activities (104,717) 38,024
--------- ---------
Net Increase in Cash and Cash Equivalents 813 6,013
Cash and Cash Equivalents at Beginning of Period 16,774 5,795
--------- ---------
Cash and Cash Equivalents at End of Period $17,587 $11,808
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $31,572,000 and
$24,853,000 and for income taxes was $33,658,000 and $2,962,000 in 2003 and
2002, respectively.
There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company in 2003.
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
----------------------------------------------
Results of Operations
- ---------------------
Net Income for the first nine months of 2003 increased $10 million due to the
adoption of SFAS 143, which resulted in a Cumulative Effect of Accounting
Changes of $9 million in the first quarter of 2003. Net Income for the third
quarter decreased $4 million due to decreased margins and increased Interest
Charges. Significant fluctuations occurred in revenues, fuel and purchased power
due to certain ICR adjustments in 2002 and changing natural gas prices; however,
income is generally not affected due to the functioning of fuel adjustment
clauses in the retail jurisdictions.
Third Quarter 2003 Compared to Third Quarter 2002
- -------------------------------------------------
Operating Income
Operating Income decreased by $1 million primarily due to:
o A $2 million decrease in retail base revenues in large part due to
a 9% decline in cooling-degree days.
o A decline in risk management activities of $5 million.
o A 19% increase in fuel expense resulting from a higher per unit cost
of fuel, mostly natural gas, offset partially by reduced purchased
power expense.
o An increase of $1 million from Taxes Other Than Income Taxes due
in large part to increased property taxes resulting from revised
tax valuations.
o A $3 million increase in Other Operation expense primarily due to
increased deferred fuel expense.
The decrease in Operating Income was partially offset by:
o An increase in retained margins from off-system sales of $6 million
due to larger volumes.
o A decrease in Maintenance expense of $1 million due mainly to
reduced scheduled power plant maintenance.
o A decrease of $1 million in Income Taxes due to a decrease in
pre-tax operating book income.
Other Impacts on Earnings
Interest Charges increased $2 million primarily due to higher overall levels of
outstanding debt.
Minority Interest expense of $1 million is a result of consolidating Sabine
Mining Company during the third quarter of 2003, due to the implementation of
FIN 46. See Notes 2 and 6 for additional discussion.
Nine Months Ended September 30, 2003 Compared to Nine Months
- ------------------------------------------------------------
Ended September 30, 2002
- ------------------------
Operating Income
Operating Income increased by $6 million primarily due to:
o An increase in retained margins from off-system sales of $11 million
due to larger volumes.
o An increase in retail base revenues of $6 million due to an
increased number of customers and their average usage, offset in
part by milder weather. Cooling degree-days declined 8% while
heating degree-days increased 2%.
o A $7 million increase in transmission revenues.
o An increase in risk management activities of $4 million.
o A decrease in Other Operation expense of $6 million primarily due
to reduced transmission expense of $4 million.
o A $2 million decrease in Maintenance expense due to reduced
scheduled power plant maintenance and reduced tree trimming expense.
The increase in Operating Income was partially offset by:
o A $7 million decrease in wholesale base margins partly due to
decreased demand from wholesale customers.
o A decrease in capacity revenues of $4 million, due to the
elimination of the requirement under the Texas Restructuring
legislation to sell capacity since they did not transition to
competition.
o An increase in fuel expense of 17% due to a higher per unit cost of
fuel, mostly natural gas, offset partially by reduced purchased
power expense.
o A $3 million increase in Taxes Other Than Income Taxes due mainly
to increased property taxes resulting from revised tax valuations.
o An increase in Income Taxes of $2 million due to an increase in
pre-tax operating book income and a change in certain book versus
tax differences accounted for on a flow-through basis.
Other Impacts on Earnings
Interest Charges increased $5 million primarily due to higher overall levels of
outstanding debt.
Minority Interest expense of $1 million is a result of consolidating Sabine
Mining Company during the third quarter of 2003, due to the implementation of
FIN 46. See Notes 2 and 6 for additional discussion.
Cumulative Effect of Accounting Changes
The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).
Financial Condition
- -------------------
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as
follows:
Moody's S&P Fitch
-------- ---- -------
First Mortgage Bonds A3 BBB A
Senior Unsecured Debt Baa1 BBB A-
In February 2003, Moody's Investors Service (Moody's) completed their review
of AEP and its rated subsidiaries. The results of that review included a
downgrade of our rating for unsecured debt from A2 to Baa1 and secured debt
from A1 to A3. The completion of this review was a culmination of ratings
action started during 2002. In March 2003, S&P lowered AEP and our senior
unsecured debt and first mortgage bonds ratings from BBB+ to BBB.
Cash Flow
Cash flows for the nine months ended September 30, 2003 and 2002 were as
follows:
2003 2002
------ ------
(in thousands)
Cash and cash equivalents at beginning of period $2,069 $5,415
Cash flows from (used for):
Operating activities 207,874 195,639
Investing activities (77,403) (72,809)
Financing activities (115,951) (122,541)
--------- ---------
Net increase in cash and cash equivalents 14,520 289
--------- ---------
Cash and cash equivalents at end of period $16,589 $5,704
========= =========
Operating Activities
Cash flows from operating activities increased $12 million in the first nine
months of 2003 compared to the first nine months of 2002 primarily due to a
change in under-recovery of fuel costs due to higher natural gas prices in 2003
and a build-up of fuel inventory during 2002.
Investing Activities
Cash spent on investing activities increased $5 million in comparison to the
prior year. In 2003, $68 million of construction expenditures were related to
projects for improved transmission and distribution service reliability.
Financing Activities
Cash flows used for financing activities in the first nine months of 2003 were
comparable to the first nine months of 2002. During the first quarter of 2003 we
retired $55 million of first mortgage bonds at maturity. In April 2003, we
issued $100 million of senior unsecured debt due 2015 at a coupon of 5.375%. In
May 2003, one of our mining subsidiaries issued $44 million of notes due in 2011
at a coupon of 4.47%. The loan will be used primarily to reduce a note to us
with an interest rate of 8.06%.
Financing Activity
Long-term debt issuances and retirements during the first nine months of 2003
were:
Issuances
---------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- -----
(in millions) (%)
Senior Unsecured Notes $100 5.375 2015
Secured Note of Subsidiary 44 4.47 2011
Retirements
-----------
Principal Interest Due
Type of Debt Amount Rate Date
------------ --------- -------- -----
(in millions) (%)
First Mortgage Bonds $55 6.625 2003
Secured Note of Subsidiary 2 4.47 2011
Notes Payable 1 Variable 2008
Significant Factors
- -------------------
NOx Reductions
The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo.
Our compliance date is May 2005. We are installing 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 of approximately $35 million. The actual cost to comply
could be significantly different than the estimate 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 5 for further
discussion.
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.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and procedures are instituted and administered at the
AEP consolidated level for all subsidiary registrants. See complete discussion
within AEP's "Qualitative And Quantitative Disclosures About Risk Management
Activities" section. The following tables provide information about the risk
management activities' effect on this specific registrant.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability
balance sheet position from one period to the next.
Roll-Forward of MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2003
(in thousands)
Domestic Power
----------------
Beginning Balance December 31, 2002 $4,050
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (354)
Fair Value of New Contracts When Entered Into
During the Period (b) -
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation
Methodology Changes -
Effect of 98-10 Rescission 151
Changes in Fair Value of Risk Management
Contracts (d) 4,161
Changes in Fair Value of Risk Management
Contracts Allocated to Regulated Jurisdictions (e) 7,690
--------
Total MTM Risk Management Contract Net
Assets 15,698
Net Non-Trading Related Derivative Contracts (531)
--------
Net Fair Value of Risk Management and Derivative
Contracts September 30, 2003 $15,167
========
(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,
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
Income. These net gains (losses) are recorded as regulatory
liabilities/assets for those subsidiaries that operate in
regulated jurisdictions.
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
our total MTM asset or liability (external sources or modeled
internally).
o The maturity, by year, of our net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash.
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2003
Remainder After
2003 2004 2005 2006 2007 2007 Total
---------- ------ ------ ----- ------ ------ -----
(in thousands)
Prices Provided by Other External
Sources - OTC Broker Quotes (a) $337 $3,773 $1,667 $1,461 $346 $- $7,584
Prices Based on Models and Other
Valuation Methods (b) 567 1,371 870 1,052 1,160 3,094 8,114
----- ------- ------- ------- ------- ------- --------
Total $904 $5,144 $2,537 $2,513 $1,506 $3,094 $15,698
===== ======= ======= ======= ======= ======= ========
(a)"Prices Provided by Other External Sources - OTC Broker Quotes"
reflects information obtained from over-the-counter brokers,
industry services, or multiple-party on-line platforms.
(b)"Prices Based on Models and Other Valuation Methods" if there is
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 varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). 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). In accordance with GAAP, all amounts are presented net of
related income taxes.
Total Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2003
Domestic
Power
----------
(in thousands)
Accumulated OCI, December 31, 2002 $(48)
Changes in Fair Value (a) 303
Reclassifications from OCI to Net
Income (b) 207
-----
Accumulated OCI Derivative Gain (Loss)
September 30, 2003 $462
=====
(a)"Changes in Fair Value" shows 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.
(b)"Reclassifications from OCI to Net Income" represents 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.
The portion of cash flow hedges in Accumulated OCI expected to be reclassified
to earnings during the next twelve months is a $807 thousand gain.
Credit Risk
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
VaR Associated with Energy Trading Contracts
The following table shows the end, high, average, and low market risk as
measured by VaR for year-to-date:
September 30, 2003 December 31, 2002
----------------------------------------- --------------------------------------
(in thousands) (in thousands)
End High Average Low End High Average Low
----- ----- -------- ----- ----- ------ --------- -----
$427 $1,212 $558 $121 $155 $474 $170 $34
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2003 and 2002
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
2003 2002 2003 2002
------ ------ ------ ------
(in thousands)
OPERATING REVENUES
- ---------------------------------------------
Electric Generation, Transmission and Distribution $347,672 $346,519 $835,193 $794,668
Sales to AEP Affiliates 13,950 15,904 63,013 53,088
--------- --------- --------- ---------
TOTAL 361,622 362,423 898,206 847,756
--------- --------- --------- ---------
OPERATING EXPENSES
- ---------------------------------------------
Fuel for Electric Generation 145,201 122,446 358,917 306,536
Purchased Electricity for Resale 6,567 29,820 29,499 40,290
Purchased Electricity from AEP Affiliates 10,055 10,257 35,706 27,817
Other Operation 53,743 51,005 131,256 137,288
Maintenance 15,959 16,767 47,707 49,547
Depreciation and Amortization 30,381 31,764 89,284 92,437
Taxes Other Than Income Taxes 16,517 15,259 45,558 42,205
Income Taxes 23,970 24,851 39,418 36,925
--------- --------- --------- ---------
TOTAL 302,393 302,169 777,345 733,045
--------- --------- --------- ---------
OPERATING INCOME 59,229 60,254 120,861 114,711
Nonoperating Income 1,364 1,203 2,711 1,618
Nonoperating Expenses 577 344 1,453 1,298
Nonoperating Income Tax Expense (Credit) 18 176 (37) 67
Interest Charges 16,981 15,143 48,058 42,856
Minority Interest (836) - (836) -
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 42,181 45,794 73,262 72,108
Cumulative Effect of Accounting Changes (Net of Tax) - - 8,517 -
--------- --------- --------- ---------
NET INCOME 42,181 45,794 81,779 72,108
Preferred Stock Dividend Requirements 57 57 172 172
--------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $42,124 $45,737 $81,607 $71,936
========= ========= ========= =========
The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND
COMPREHENSIVE INCOME (LOSS)
(in thousands)
(Unaudited)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------- -------- --------- ----------------- ------
JANUARY 1, 2002 $135,660 $245,003 $308,915 $- $689,578
Common Stock Dividends (56,889) (56,889)
Preferred Stock Dividends (172) (172)
---------
TOTAL 632,517
---------
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges 50 50
NET INCOME 72,108 72,108
---------
TOTAL COMPREHENSIVE INCOME 72,158
--------- --------- --------- --------- ---------
SEPTEMBER 30, 2002 $135,660 $245,003 $323,962 $50 $704,675
========= ========= ========= ========= =========
JANUARY 1, 2003 $135,660 $245,003 $334,789 $(53,683) $661,769
Common Stock Dividends (54,596) (54,596)
Preferred Stock Dividends (172) (172)
---------
607,001
---------
COMPREHENSIVE INCOME
- -----------------------------------------
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Hedges 510 510
NET INCOME 81,779 81,779
---------
TOTAL COMPREHENSIVE INCOME 82,289
--------- --------- --------- --------- ---------
SEPTEMBER 30, 2003 $135,660 $245,003 $361,800 $(53,173) $689,290
========= ========= ========= ========= =========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
------ ------
(in thousands)
ELECTRIC UTILITY PLANT
- -------------------------------------------------------
Production $1,651,234 $1,503,722
Transmission 609,775 575,003
Distribution 1,071,355 1,063,564
General 409,012 378,130
Construction Work in Progress 54,797 75,755
----------- -----------
TOTAL 3,796,173 3,596,174
Accumulated Depreciation and Amortization 1,852,603 1,697,338
----------- -----------
TOTAL - NET 1,943,570 1,898,836
----------- -----------
Other Property and Investments 6,516 5,978
Long-term Risk Management Assets 18,804 5,119
CURRENT ASSETS
- -------------------------------------------------------
Cash and Cash Equivalents 16,589 2,069
Advances to Affiliates 123,790 -
Accounts Receivable:
Customers 43,782 62,359
Affiliated Companies 49,204 19,253
Allowance for Uncollectible Accounts (2,140) (2,128)
Fuel Inventory 57,499 61,741
Materials and Supplies 34,227 33,539
Under-recovered Fuel Costs - 2,865
Risk Management Assets 15,041 4,388
Prepayments and Other 19,978 17,851
----------- -----------
TOTAL 357,970 201,937
----------- -----------
Regulatory Assets 52,715 49,233
Deferred Charges 70,183 47,572
TOTAL ASSETS $2,449,758 $2,208,675
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
------ ------
(in thousands)
CAPITALIZATION
- ------------------------------------------------------------
Common Shareholder's Equity:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $135,660 $135,660
Paid-in Capital 245,003 245,003
Accumulated Other Comprehensive Income (Loss) (53,173) (53,683)
Retained Earnings 361,800 334,789
----------- -----------
Total Common Shareholder's Equity 689,290 661,769
Cumulative Preferred Stock Not Subject to Mandatory Redemption 4,700 4,701
SWEPCo - Obligated, Mandatorily Redeemable Preferred Securities of
Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo - 110,000
Long-term Debt 833,055 637,853
----------- -----------
TOTAL 1,527,045 1,414,323
----------- -----------
Minority Interest 1,651 -
Other Noncurrent Liabilities 111,107 78,494
CURRENT LIABILITIES
- ------------------------------------------------------------
Long-term Debt Due Within One Year 95,424 55,595
Advances from Affiliates, Net - 23,239
Accounts Payable - General 49,352 62,139
Accounts Payable - Affiliated Companies 56,345 58,773
Customer Deposits 23,659 20,110
Taxes Accrued 62,641 19,081
Interest Accrued 15,308 17,051
Risk Management Liabilities 9,876 3,724
Over-recovered Fuel 611 17,226
Other 45,661 34,565
----------- -----------
TOTAL 358,877 311,503
----------- -----------
Deferred Income Taxes 352,601 341,064
Deferred Investments Tax Credits 40,945 44,190
Regulatory Liabilities and Deferred Credits 48,730 17,295
Long-term Risk Management Liabilities 8,802 1,806
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES $2,449,758 $2,208,675
=========== ===========
See Notes to Respective Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2003 and 2002
(Unaudited)
2003 2002
------ ------
(in thousands)
OPERATING ACTIVITIES
- --------------------------------------------------------------
Net Income $81,779 $72,108
Adjustments to Reconcile Net Income to Net Cash Flows
From Operating Activities:
Depreciation and Amortization 89,284 92,437
Deferred Income Taxes 421 (15,296)
Deferred Investment Tax Credits (3,245) (3,393)
Cumulative Effect of Accounting Changes (8,517) -
Mark-to-Market of Risk Management Contracts (11,497) (4,534)
Changes in Certain Assets and Liabilities:
Accounts Receivable, Net (8,862) (10,293)
Fuel, Materials and Supplies 10,095 (6,596)
Accounts Payable (18,773) 7,280
Taxes Accrued 42,396 56,866
Fuel Recovery (13,750) 24,660
Deferred Property Taxes (9,315) (8,772)
Change in Other Assets (3,088) (24,717)
Change in Other Liabilities 60,946 15,889
--------- ---------
Net Cash Flows From Operating Activities 207,874 195,639
--------- ---------
INVESTING ACTIVITIES
- --------------------------------------------------------------
Construction Expenditures (86,488) (73,483)
Proceeds from Sale of Assets and Other 9,085 674
--------- ---------
Net Cash Flows Used For Investing Activities (77,403) (72,809)
--------- ---------
FINANCING ACTIVITIES
- --------------------------------------------------------------
Issuance of Long-term Debt 144,324 198,614
Retirement of Long-term Debt (58,478) (150,450)
Change in Advances to/from Affiliates, Net (147,029) (113,644)
Dividends Paid on Common Stock (54,596) (56,889)
Dividends Paid on Cumulative Preferred Stock (172) (172)
--------- ---------
Net Cash Flows Used For Financing Activities (115,951) (122,541)
--------- ---------
Net Increase in Cash and Cash Equivalents 14,520 289
Cash and Cash Equivalents at Beginning of Period 2,069 5,415
--------- ---------
Cash and Cash Equivalents at End of Period $16,589 $5,704
========= =========
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $45,211,000 and
$34,860,000 and for income taxes was $26,166,000 and $24,102,000 in 2003 and
2002, respectively.
See Notes to Respective Financial Statements beginning on page L-1.
NOTES TO RESPECTIVE FINANCIAL STATEMENTS
----------------------------------------
SEPTEMBER 30, 2003
------------------
(Unaudited)
The notes to financial statements that follow are a combined presentation for
AEP's subsidiary registrants. The following list indicates the registrants to
which the footnotes apply:
1. General AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2. New Accounting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Pronouncements and
Cumulative Effect of
Accounting Changes
3. Rate Matters APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4. Customer Choice and APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
Industry Restructuring
5. Commitments and AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Contingencies
6. Guarantees AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7. Business Segments AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
8. Leases OPCo
9. Financing and Related AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
Activities
1. GENERAL
-------
The accompanying unaudited interim financial statements should be read
in conjunction with the 2002 Annual Report (as updated by the Current
Report on Form 8-K dated May 14, 2003) as incorporated in and filed
with the Form 10-K.
Certain prior period financial statement items have been reclassified
to conform to current period presentation. These items include gains and
losses associated with derivative trading contracts presented on a net
basis in accordance with EITF 02-3, and counterparty netting in
accordance with FASB Interpretation No. 39, "Offsetting of Amounts
Related to Certain Contracts" and EITF Topic D-43, "Assurance That a
Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation
No. 39." Such reclassifications had no effect on previously reported Net
Income.
In the opinion of management, the unaudited interim financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
2. NEW ACCOUNTING PRONOUNCEMENTS AND CUMULATIVE EFFECT OF ACCOUNTING
-----------------------------------------------------------------
CHANGES
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FIN 46 "Consolidation of Variable Interest Entities"
We implemented FIN 46, "Consolidation of Variable Interest Entities,"
effective July 1, 2003. FIN 46 interprets the application of Accounting
Research Bulletin No. 51, "Consolidated Financial Statements," to
certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support from other parties.
Due to the prospective application of FIN 46, we did not reclassify
prior period amounts.
On July 1, 2003, we deconsolidated the trusts which hold mandatorily
redeemable trust preferred securities. Therefore, $321 million ($75
million PSO, $110 million SWEPCo and $136 million TCC), previously
reported as Certain Subsidiary Obligated, Mandatorily Redeemable,
Preferred Securities of Subsidiary Trusts Holding Solely Junior
Subordinated Debentures of Such Subsidiaries, is now reported as a
component of Long-term Debt.
Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company
(Sabine), a contract mining operation providing mining services to
SWEPCo. Upon consolidation, SWEPCo recorded the assets and liabilities
of Sabine ($77.8 million). Also, after consolidation, SWEPCo currently
records all expenses (depreciation, interest and other operation
expense) of Sabine and eliminates Sabine's revenues against SWEPCo's
fuel expenses. There is no cumulative effect of an accounting change
recorded as a result of our requirement to consolidate, and there is no
change in net income due to the consolidation of Sabine.
Effective July 1, 2003, OPCo consolidated JMG Funding, LP (JMG). Upon
consolidation, OPCo recorded the assets and liabilities of JMG ($469.6
million). OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's
operating lease expenses. There is no cumulative effect of an accounting
change recorded as a result of our requirement to consolidate JMG, and
there is no change in net income due to the consolidation of JMG. See
Note 8 "Leases" for further disclosures.
SFAS 143 "Accounting for Asset Retirement Obligations"
We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability
at fair value for any legal obligations for asset retirements in the
period incurred. Upon establishment of a legal liability, SFAS 143
requires a corresponding asset to be established which will be
depreciated over its useful life. SFAS 143 requires that a cumulative
effect of change in accounting principle be recognized for the
cumulative accretion and accumulated depreciation that would have been
recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in
accounting principle is favorably affected by the reversal of
accumulated removal cost. These costs had previously been recorded for
generation and did not qualify as a legal obligation although these
costs were collected in depreciation rates by certain formerly
regulated subsidiaries.
We completed a review of our asset retirement obligations and concluded
that we have related legal liabilities for nuclear decommissioning costs
for I&M's Cook Plant and TCC's partial ownership in the South Texas
Project, as well as liabilities for the retirement of certain ash ponds.
Since we presently recover our nuclear decommissioning costs in our
regulated cash flow and have existing balances recorded for such nuclear
retirement obligations, we recognized the cumulative difference in the
amount already provided through rates and the amount as measured by
applying SFAS 143, as a regulatory asset or liability. Similarly, a
regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In
the first quarter of 2003, AEP recorded an unfavorable cumulative effect
for its non-regulated operations. See the table later in this section
for a summary by registrant subsidiary of the cumulative effect of
changes in accounting principles for the nine months ended September 30,
2003.
Certain of AEP's registrant subsidiaries have recorded in Accumulated
Depreciation and Amortization, removal costs collected from ratepayers
for certain assets that do not have associated legal asset retirement
obligations. To the extent that such registrant subsidiaries have now
been deregulated, in the first quarter 2003 the registrant subsidiaries
reversed the balance of such removal costs from accumulated depreciation
which resulted in a net favorable cumulative effect in the first quarter
of 2003. However, the registrant subsidiaries did not adjust the balance
of such removal costs for their regulated operations, and in accordance
with the present method of recovery, will continue to record such
amounts through depreciation expense and accumulated depreciation.
The following is a summary by registrant subsidiary of the regulatory
liabilities for removal costs included in Accumulated Depreciation and
Amortization:
September 30, 2003 December 31, 2002
------------------ -----------------
(in millions)
AEGCo $ 28.6 $ 28.0
APCo 90.0 94.6
CSPCo 98.0 96.0
I&M 260.9 250.5
KPCo 22.0 23.7
OPCo 97.6 97.0
PSO 203.7 202.6
SWEPCo 229.5 219.5
TCC 101.7 97.5
TNC 76.4 75.0
The following is a summary by registrant subsidiary of the cumulative
effect of changes in accounting principles, as a result of SFAS 143,
for the nine months ended September 30, 2003:
Pre-tax Income (Loss) After-tax Income (Loss)
--------------------- -----------------------
(in millions)
Reversal of
Cost of Reversal of
Ash Ponds Removal Ash Ponds Cost of Removal
--------- ------------ ---------- -----------------
AEGCo $ - $ - $ - $ -
APCo (18.2) 146.5 (11.4) 91.7
CSPCo (7.8) 56.8 (4.7) 33.9
I&M - - - -
KPCo - - - -
OPCo (36.8) 250.4 (21.9) 149.3
PSO - - - -
SWEPCo - 13.0 - 8.4
TCC - - - -
TNC - 4.7 - 3.1
We have identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution as a
result of certain easements on property on which we have assets.
Generally, such easements are perpetual and require only the retirement
and removal of our assets upon the cessation of the property's use. The
retirement obligation is not estimable for such easements since we plan
to use our facilities indefinitely. The retirement obligation would only
be recognized if and when we abandon or cease the use of specific
easements.
The following is a reconciliation of beginning and ending aggregate
carrying amounts of asset retirement obligations by registrant
subsidiary following the adoption of SFAS 143:
Balance At Balance at
January 1, Liabilities September 30,
2003 Accretion Incurred 2003
---------- ----------- ------------ -------------
(in millions)
AEGCo (a) $1.1 $- $- $1.1
APCo (a) 20.1 1.2 - 21.3
CSPCo (a) 8.1 0.5 - 8.6
I&M (b) 516.1 27.6 - 543.7
OPCo (a) 39.5 2.3 - 41.8
SWEPCo (d) - 0.2 8.1 8.3
TCC (c) 203.2 11.6 - 214.8
(a) Consists of asset retirement obligations related to ash ponds.
(b) Consists of asset retirement obligations related to ash ponds
($1.1 million at September 30, 2003) and nuclear
decommissioning costs for the Cook Plant ($542.6 million at
September 30, 2003).
(c) Consists of asset retirement obligations related to nuclear
decommissioning costs for STP.
(d) Consists of asset retirement obligations related to Sabine
Mining which is now being consolidated under FIN 46 (see FIN
46 "Consolidation of Variable Interest Entities" above).
Accretion expense is included in Other Operation expense in the
respective Income Statements of the individual subsidiary registrants.
As of September 30, 2003 and December 31, 2002, the fair value of assets
that are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $800 million ($685 million for I&M
and $115 million for TCC) and $716 million ($618 million for I&M and $98
million for TCC), respectively, recorded in Nuclear Decommissioning and
Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated Balance
Sheets and in Nuclear Decommissioning Trust Fund on TCC's Consolidated
Balance Sheets.
Pro forma net income has not been presented for the quarter ended
September 30, 2002 or the years ended December 31, 2002, 2001 and 2000
because the pro forma application of SFAS 143 would result in pro forma
net income not materially different from the actual amounts reported for
those periods.
The following is a summary by registrant subsidiary of the pro forma
liability for asset retirement obligations which has been calculated as
if SFAS 143 had been adopted as of the beginning of each period
presented:
December 31, 2002 December 31, 2001
------------------ -------------------
(in millions)
AEGCo $ 1.1 $ 1.0
APCo 20.1 18.7
CSPCo 8.1 7.5
I&M 516.1 481.4
KPCo - -
OPCo 39.5 36.5
PSO - -
SWEPCo - -
TCC 203.2 188.8
TNC - -
Rescission of EITF 98-10
In October 2002, the Emerging Issues Task Force of the FASB reached a
final consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and
related interpretive guidance. Under EITF 02-3, mark-to-market
accounting is precluded for energy trading contracts that are not
derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10
also eliminated the recognition of physical inventories at fair value
other than as provided by GAAP. We have implemented this standard for
all physical inventory and non-derivative energy trading transactions
occurring on or after October 25, 2002. For physical inventory and
non-derivative energy trading transactions entered into prior to October
25, 2002, we implemented this standard on January 1, 2003 and reported
the effects of implementation as a cumulative effect of an accounting
change.
The following is a summary by registrant subsidiary of the cumulative
effect of changes in accounting principles recorded in the first quarter
of 2003 for the adoptions of SFAS 143 and EITF 02-3 (no effect on AEGCo
or PSO):
SFAS 143 Cumulative Effect EITF 02-3 Cumulative Effect
---------------------------- -----------------------------
Pre-tax After-tax Pre-tax After-tax
Income (Loss) Income (Loss) Income (Loss) Income (Loss)
------------- ------------- ------------- -------------
(in millions) (in millions)
APCo $128.3 $ 80.3 $ (4.7) $ (3.0)
CSPCo 49.0 29.3 (3.1) (2.0)
I&M - - (4.9) (3.2)
KPCo - - (1.7) (1.1)
OPCo 213.6 127.3 (4.2) (2.7)
SWEPCo 13.0 8.4 0.2 0.1
TCC - - 0.2 0.1
TNC 4.7 3.1 - -
SFAS 149 "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
On April 30, 2003, the FASB issued Statement No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS
149). SFAS 149 amends SFAS 133 to clarify the definition of a derivative
and the requirements for contracts to qualify as "normal purchase/normal
sale." SFAS 149 also amends certain other existing pronouncements.
Effective July 1, 2003, we implemented SFAS 149 and the effect was not
material to our results of operations, cash flows or financial
condition.
SFAS 150 "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the result
of the first phase of the FASB's project to eliminate from the balance
sheet the "mezzanine" presentation of items with characteristics of both
liabilities and equity.
SFAS 150 requires that the following three types of freestanding
financial instruments be reported as liabilities: (1) mandatorily
redeemable shares, (2) instruments other than shares that could require
the issuer to buy back some of its shares in exchange for cash or other
assets and (3) obligations that can be settled with shares, the monetary
value of which is either (a) fixed, (b) tied to the value of a variable
other than the issuer's shares, or (c) varies inversely with the value
of the issuer's shares. Measurement of these liabilities generally is to
be at fair value, with the payment or accrual of "dividends" and other
amounts to holders reported as interest cost. Upon adoption of SFAS 150,
any measurement change for these liabilities is to be reported as the
cumulative effect of a change in accounting principle.
Beginning with the third quarter 2003 financial statements, $83 million
($11 million APCo, $63 million I&M and $9 million OPCo) of Cumulative
Preferred Stock Subject to Mandatory Redemption is now presented as
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption
within the Capitalization section of the balance sheet in order to
identify it as a liability. Beginning July 1, 2003, dividends on these
mandatorily redeemable preferred shares are now classified as Interest
Charges on the statements of operations. In accordance with SFAS 150,
dividends from prior periods remain classified as Preferred Stock
Dividends.
FIN 45 "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
In November 2002, the FASB issued FIN 45 which clarifies the accounting
to recognize a liability related to issuing a guarantee, as well as
additional disclosures of guarantees. This guidance is an interpretation
of SFAS 5, 57 and 107 and a rescission of FIN 34. The initial
recognition and initial measurement provisions of FIN 45 are effective
on a prospective basis for guarantees issued or modified after December
31, 2002. The disclosure requirements of FIN 45 are effective for
financial statements of interim or annual periods ending after December
15, 2002. See Note 6 for further disclosures.
Future Accounting Changes
FASB's standard-setting process is ongoing. Until new standards have
been finalized and issued by FASB, we cannot determine the impact on the
reporting of our operations that may result from any such future
changes.
3. RATE MATTERS
------------
Fuel in SPP Area of Texas - Affecting SWEPCo and TNC
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT
delayed the start of customer choice in the SPP area of Texas. In May
2003, the PUCT ordered that competition would not begin in the SPP area
before January 1, 2007. The PUCT has ruled that TNC fuel factors in the
SPP area will be based upon the PTB fuel factors offered by the REP in
the ERCOT portion of TNC's service territory. TNC filed with the PUCT in
2002 to determine the most appropriate method to reconcile fuel costs in
TNC's SPP area. In April 2003, the PUCT issued an order adopting the
methodology proposed in TNC's filing, with adjustments, for reconciling
fuel costs in its SPP area. The adjustments removed $3.71 per MWH from
reconcilable fuel expense. This adjustment will reduce revenues received
from TNC's SPP customers by approximately $400,000 annually. These
customers are now served by SWEPCo's REP.
TNC Fuel Reconciliation - Affecting TNC
In June 2002, TNC filed with the PUCT to reconcile fuel costs and to
defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 2000 through December 2001 will be
the final fuel reconciliation for TNC's ERCOT service territory. At
December 31, 2001, the under-recovery balance associated with TNC's
ERCOT service area was $27.5 million including interest. During the
reconciliation period, TNC incurred $293.7 million of eligible fuel
costs serving both ERCOT and SPP retail customers. TNC also requested
authority to surcharge its SPP customers for under-recovered fuel costs.
TNC's SPP customers will continue to be subject to fuel reconciliations
until competition begins in the SPP area. The under-recovery balance at
December 31, 2001 for TNC's service within SPP was $0.7 million
including interest. As noted above, TNC's SPP customers are now being
served by SWEPCo's REP.
In March 2003, the Administrative Law Judges (ALJ) in this proceeding
filed their Proposal for Decision (PFD). The PFD includes a
recommendation that TNC's under-recovered retail fuel balance be reduced
by approximately $12.5 million. In March 2003, TNC established a reserve
of $13 million, including interest, based on the recommendations in the
PFD. On April 22, 2003, TNC and intervenors in this proceeding filed
exceptions to the PFD. On May 28, 2003, the PUCT remanded TNC's final
fuel reconciliation to the ALJ to consider two issues. These remand
issues could result in additional disallowances. The issues are the
sharing of off-system sales margins from AEP's trading activities with
customers through the fuel factor for five years per the PUCT's
interpretation of the Texas AEP/CSW merger settlement and the inclusion
of January 2002 fuel factor revenues and associated costs in the
determination of the under-recovery. The PUCT is proposing that the
sharing of off-system sales margins should continue beyond the
termination of the fuel factor. This would result in the sharing of
margins for an additional three and one half years after the end of the
Texas ERCOT fuel factor. TNC made a filing on July 15, 2003 addressing
the remand issues. Intervenors and the PUCT Staff filed statements of
position or testimony in August 2003 and TNC filed rebuttal testimony in
September 2003. The intervenors recommended $14.3 million of
disallowances for the two remanded issues. On September 9, 2003,
portions of TNC's testimony which related to the requirements of the
AEP/CSW merger settlement to share off-system sales margins were
stricken by the ALJ. The ALJ ruled that the requirement to share
off-system sales margins had been determined by the PUCT and that the
scope of the remand was only to determine the off-system sales margin
sharing methodology. Management believes that the Texas merger
settlement only provided for sharing of margins during the period fuel
and generation costs were regulated by the PUCT and that after a
thorough review of the evidence it is only reasonably possible that TNC
will ultimately share margins after the end of the Texas fuel factor.
Due to a provision established in the first quarter of 2003, the
resolution of the fuel factor issue should have an immaterial impact on
future results of operations, cash flows and financial condition.
However, the ultimate decision could result in additional income
reductions for these issues. It is presently expected that the ALJ's PFD
and the PUCT's final decision regarding these remanded issues will occur
in late 2003 or early 2004.
In February 2002, TNC received a final order from the PUCT in a fuel
reconciliation covering the period July 1997 to June 2000 and reflected
the order in its financial statements. This final order was appealed to
the Travis County District Court. In May 2003, the District Court upheld
the PUCT's final order. That order is currently on appeal to the Third
Court of Appeals.
TCC Fuel Reconciliation - Affecting TCC
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
defer its over-recovery of fuel for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 1998 through
December 2001 will be TCC's final fuel reconciliation. At December 31,
2001, the over-recovery balance for TCC was $63.5 million including
interest. During the reconciliation period, TCC incurred $1.6 billion of
eligible fuel and fuel-related expenses. Recommendations from
intervening parties were received in April 2003 and hearings were held
in May 2003. Intervening parties have recommended disallowances totaling
$170 million. An ALJ report is expected in 2003 or the first quarter of
2004.
In March 2003, the ALJ hearing the TNC final fuel reconciliation,
discussed above, issued a PFD in the TNC proceeding. Various issues
addressed in TNC's proceeding may also be applicable to TCC's
proceeding. Consequently, TCC established a reserve for potential
adverse rulings of $27 million during the first quarter of 2003. Based
upon the PUCT's remand of certain TNC issues, TCC established an
additional reserve of $9 million in the second quarter of 2003. In July
2003, the ALJ requested that additional information be provided in the
TCC fuel reconciliation related to the impact of the TNC remand order on
TCC. Management believes, based on advice of counsel, that it is only
reasonably possible that it will ultimately be determined that TCC
should share off-system sales margins after the end of the Texas fuel
factor. However, an adverse ruling could have a material impact on
future results of operations, cash flows and financial condition.
Additional information regarding the 2004 true-up proceeding for TCC can
be found in Note 4 "Customer Choice and Industry Restructuring."
SWEPCo Texas Fuel Reconciliation - Affecting SWEPCo
In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This
reconciliation covers the period of January 2000 through December 2002.
At December 31, 2002, SWEPCo's filing detailed a $2.2 million
over-recovery balance including interest. During the reconciliation
period, SWEPCo incurred $434.8 million of eligible fuel expense. Any
ruling by the PUCT preventing recovery of SWEPCo's fuel costs could have
a material impact on future results of operations, cash flows and
financial condition. Intervenor and PUCT Staff recommendations will be
filed in November 2003 and hearings are scheduled for January 2004.
ERCOT Price-to-Beat Fuel Factor Appeal - Affecting TCC and TNC
Several parties including the Office of Public Utility Counsel (OPC) and
cities served by both TCC and TNC appealed the PUCT's December 2001
orders establishing initial PTB fuel factors for Mutual Energy CPL and
Mutual Energy WTU. On June 25, 2003, the District Court ruled in both
appeals. The Court ruled in the Mutual Energy WTU case that the PUCT
lacked sufficient evidence to include unaccounted for energy in the fuel
factor, and that the PUCT improperly shifted the burden of proof and the
record lacked substantial evidence on the effect of loss of load due to
retail competition on generation requirements. The Court upheld the
initial PTB orders on all other issues. In the Mutual Energy CPL
proceeding, the Court ruled that the PUCT improperly shifted the burden
of proof and the record lacked substantial evidence on the effect of
loss of load due to retail competition on generation requirements. The
Court remanded the cases to the PUCT for further proceedings consistent
with its ruling. The amount of unaccounted for energy built into the PTB
fuel factors was approximately $2.7 million for Mutual Energy WTU. At
this time, management is unable to estimate the potential financial
impact related to the loss of load issue. Management appealed the
District Court decisions to the Third Court of Appeals and believes,
based on the advice of counsel, that the PUCT's original decision will
ultimately be upheld. If the District Court's decisions are ultimately
upheld, the PUCT could reduce the PTB fuel factors charged to retail
customers in 2002 and 2003 resulting in an adverse effect on future
results of operations and cash flows.
Unbundled Cost of Service (UCOS) Appeal - Affecting TCC
TCC placed new transmission and distribution rates into effect as of
January 1, 2002 based upon an order issued by the PUCT resulting from an
UCOS proceeding. TCC requested and received approval from the FERC of
wholesale transmission rates determined in the UCOS proceeding. The UCOS
proceeding set the regulated wires rates to be effective when retail
electric competition began. Regulated delivery charges include the
retail transmission and distribution charge including a nuclear
decommissioning fund charge and a municipal franchise fee, a system
benefit fund fee, a transition charge associated with securitization of
regulatory assets and a credit for excess earnings. Certain rulings of
the PUCT in the UCOS proceeding, including the initial determination of
stranded costs, the requirement to refund TCC's excess earnings,
regulatory treatment of nuclear insurance and distribution rates charged
municipal customers, were appealed to the Travis County District Court
by TCC and other parties to the proceeding. The District Court issued a
decision on June 16, 2003, upholding the PUCT's UCOS order with one
exception. The Court ruled that the refund of the 1999 through 2001
excess earnings solely as a credit to non-bypassable transmission and
distribution rates charged to REPs discriminates against residential and
small commercial customers and is unlawful. The distribution rate credit
began in January 2002. This decision could potentially affect the PTB
rates charged by the AEP REP (Mutual Energy CPL) and could result in a
refund to certain of its customers. Mutual Energy CPL was a subsidiary
of AEP until December 23, 2002 when it was sold. Management estimates
that the effect of reducing the PTB rates for the period prior to the
sale is approximately $11 million pre-tax. Management has appealed this
decision and, based on advice of counsel, believes that it will
ultimately prevail on appeal. If the District Court's decision is
ultimately upheld on appeal, it could have an adverse effect on future
results of operations and cash flows.
McAllen Rate Review - Affecting TCC
On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates
should not be reduced. Other municipalities served by TCC passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC has a minimum of 120 days to provide
support for its rates to the municipalities. TCC has the right to appeal
any rate change by the municipalities to the PUCT. Pursuant to an
agreement with the cities, TCC filed the requested support for its rates
(test year ending June 30, 2003) with both the cities and the PUCT on
November 3, 2003. TCC filed to decrease its wholesale transmission rates
by $2 million or 2.5% and increase its retail energy delivery rates by
$69 million or 19.2%. Management is unable to predict the ultimate
effect of this proceeding on TCC's rates or its impact on TCC's results
of operations, cash flows and financial condition.
Louisiana Fuel Audit - Affecting SWEPCO
The LPSC is performing an audit of SWEPCo's historical fuel costs. In
addition, five SWEPCo customers filed a suit in the Caddo Parish
District Court in January 2003 and filed a complaint with the LPSC. The
customers claim that SWEPCo has over charged them for fuel costs since
1975. The LPSC consolidated the customer complaint and audit. A
procedural schedule has been developed requiring LPSC Staff and
intervenor testimony be filed in January 2004. Management believes that
SWEPCo's fuel costs prior to 1999 were proper and have been approved by
the LPSC and that SWEPCo's historical fuel costs are reasonable. If the
actions of the LPSC or the Court result in a material disallowance of
recovery of SWEPCo's fuel costs from customers, it could have an adverse
impact on results of operations and cash flows.
FERC Wholesale Fuel Complaints - Affecting TNC
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), certain TNC wholesale customers filed a
complaint with FERC alleging that TNC had overcharged them through the
fuel adjustment clause for certain purchased power costs since 1997.
Negotiations to settle the complaint and update the contracts have
resulted in new contracts. Consequently, an offer of settlement was
filed at FERC in June 2003 regarding the fuel complaint and new
contracts. Management is unable to predict whether FERC will approve
this offer of settlement, but it is not expected to have a significant
impact on TNC's financial condition. In March 2002, TNC recorded a
provision for refund of $2.2 million before income taxes. TNC
anticipates that the provision for refund will be adequate to cover the
financial implications resulting from these new contracts. Should FERC
fail to approve the settlement and new contracts, the actual refund and
final resolution of this matter could differ materially from the
provision and may have a negative impact on future results of
operations, cash flows and financial condition.
Environmental Surcharge Filing - Affecting KPCo
In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million)
to recover the cost of emissions control equipment being installed at
Big Sandy Plant. See NOx Reductions in Note 5.
In March 2003, the KPSC granted approximately $18 million of the
request. Annual rate relief of $1.7 million was effective in May 2003
and an additional $16.2 million was effective in July 2003. The recovery
of such amounts is intended to offset KPCo's cost of compliance with the
Clean Air Act.
PSO Rate Review - Affecting PSO
In February 2003, the Director of the OCC filed an application requiring
PSO to file all documents necessary for a general rate review before
August 1, 2003 (revised to October 31, 2003). In October 2003, PSO filed
the required data for this case and requested an increase of $36 million
annually, which is an 8.7% increase over existing base rates. A
procedural schedule has not been set for this case. Management is unable
to predict the ultimate effect of this review on PSO's rates or its
impact on PSO's results of operations, cash flows and financial
condition.
PSO Fuel and Purchased Power - Affecting PSO
As discussed in Note 6 of the 2002 Annual Report (as updated by the
Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million
under-recovery of fuel costs resulting from a reallocation in 2002 of
purchased power costs for periods prior to January 1, 2002. On July 23,
2003, PSO filed with the OCC seeking recovery of the $44 million over an
eighteen-month time period. In August 2003, the OCC Staff filed
testimony recommending recovery of $42.4 million ($44 million less two
audit adjustments) over three years. In September 2003, the OCC expanded
the case to include a full prudence review of PSO's 2001 fuel and
purchased power practices. If the OCC does not permit recovery of the
$42.4 million or determines, as a result of the review, that material
fuel and purchased power cost should not be recovered, there will be an
adverse effect on PSO's results of operations, cash flows and possibly
financial condition.
Merger Mitigation Sales - Affecting PSO, SWEPCo, TCC and TNC
As a condition of AEP/CSW merger approval at the FERC, the AEP West
companies were required to mitigate market power concerns in SPP by
divesting 300 MW of SPP capacity and selling 300 MW of SPP capacity at
auction on an interim basis until the divestiture is completed. The
margins from the interim sales were to be shared with customers in
accordance with the existing margin sharing if they were positive on an
annual basis and customers were to be held harmless if the margins on an
annual basis were negative. Consequently, for proper accounting, the
margins were deferred until year end.
On September 1, 2003, AEP sold its share of the Eastex plant located in
SPP. As a result of the sale, AEP satisfied the 300 MW FERC divestiture
requirement in SPP. Based on the advice of counsel, management has
concluded that it is no longer required to make the agreed upon 300 MW
interim merger mitigation sale. The AEP West companies had $8.7 million
of net merger mitigation sales losses deferred. Since these sales are no
longer required, the final adjustment to the accrual occurred in
September 2003. The amounts of revenues reversed were $8.6 million by
PSO, $0.7 million by TCC and $1.2 million by TNC. SWEPCo recorded its
gain of $1.8 million as revenues.
Virginia Fuel Factor Filing - Affecting APCo
APCo filed with the Virginia SCC to reduce its fuel factor effective
August 1, 2003. The requested fuel rate reduction would be effective for
17 months and is estimated to reduce revenues by $36 million during that
17-month period. By order dated July 23, 2003, the Virginia SCC approved
APCo's requested fuel factor reduction on an interim basis, subject to
further investigation. No other parties to the proceeding have raised
any issues with respect to APCo's request and the Virginia SCC Staff has
filed testimony recommending that APCo's request be approved. This fuel
factor adjustment will reduce cash flows without impacting results of
operations as any over-recovery or under-recovery of fuel costs would be
deferred as a regulatory liability or a regulatory asset. A hearing on
this matter was held on November 5, 2003.
FERC Long-term Contracts - Affecting AEP East and AEP West companies
In September 2002, the FERC voted to hold hearings to consider requests
from certain wholesale customers located in Nevada and Washington to
break long-term contracts which they allege are "high-priced." At issue
are long-term contracts entered into during the California energy price
spike in 2000 and 2001. The complaints allege that AEP sold power at
unjust and unreasonable prices. The FERC delayed hearings to allow the
parties to hold settlement discussions. In January 2003, the FERC
settlement judge indicated that the parties' settlement efforts were not
progressing and he recommended that the complaint be placed back on the
schedule for a hearing. In February 2003, AEP and one of the customers
agreed to terminate their contract. The customer withdrew its FERC
complaint and paid $59 million to AEP. As a result of the contract
termination, AEP reversed $69 million of unrealized mark-to-market gains
previously recorded, resulting in a $10 million pre-tax loss.
In a similar complaint, a FERC administrative law judge (ALJ) ruled in
favor of AEP and dismissed, in December 2002, a complaint filed by two
Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the
utilities for future delivery. In late 2001, the utilities filed
complaints that the prices for power supplied under those contracts
should be lowered because the market for power was allegedly
dysfunctional at the time such contracts were consummated. The ALJ
rejected the utilities' complaint, held that the markets for future
delivery were not dysfunctional, and that the utilities had failed to
demonstrate that the public interest required that changes be made to
the contracts. At a hearing held in April 2003, the utilities asked FERC
to void the long-term contracts. In June 2003, the FERC issued an order
affirming the ALJ's decision and denying the utilities' complaint. The
utilities requested a rehearing. In August 2003, the FERC granted the
request for rehearing. Management is unable to predict the outcome of
this proceeding or its impact on future results of operations and cash
flows.
RTO Formation/Integration Costs - Affecting APCo, CSPCo, I&M,
KPCo, and OPCo
With FERC approval, AEP East companies have been deferring costs
incurred under FERC orders to form an RTO (the Alliance RTO) or join an
existing RTO (PJM). In July 2003, the FERC issued an order approving our
continued deferral of both our Alliance formation costs and our PJM
integration costs including the deferral of a carrying charge. The AEP
East companies have deferred approximately $24 million of RTO formation
and integration costs and related carrying charges (APCo-$7 million,
CSPCo-$3 million, I&M-$5 million, KPCo-$1 million, OPCo-$8 million)
through September 30, 2003. As a result of the subsequent delay in the
integration of AEP's East transmission system into PJM, FERC declined to
rule, in its July order, on our request to transfer the deferrals to
regulatory assets, and to maintain the deferrals until such time as the
costs can be recovered from all users of AEP's East transmission system.
The AEP East companies will apply for permission to transfer the
deferred formation/integration costs to a regulatory asset prior to
integration with PJM. In August 2003, the Virginia SCC filed a request
for rehearing of the July order, arguing that FERC's action was an
infringement on state jurisdiction, and that FERC should not have
treated Alliance RTO startup costs in the same manner as PJM integration
costs. On October 22, 2003, FERC denied the rehearing request.
In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO until after June 30, 2004 and only
then with the approval of the Virginia SCC. In July 2003, the KPSC
denied KPCo's request to join PJM based in part on a lack of evidence
that it would benefit Kentucky retail customers. In August 2003, KPCo
sought and was granted a rehearing allowing us to submit additional
evidence. A hearing date has not been scheduled.
In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to
certain conditions included in the order. The IURC's order stated that
AEP shall request and the IURC shall complete a review of Alliance
formation costs ($2 million for I&M) before any deferral of the costs
for future recovery. On September 30, 2003, AEP filed a petition for
reconsideration of the IURC's order, asking the IURC to clarify that its
discussion of the Alliance formation costs was not intended to cause an
immediate write-off of the Indiana retail portion of these costs.
In its July 2003 order, FERC indicated that it would review the deferred
costs at the time they are transferred to a regulatory asset account and
scheduled for amortization and recovery in the open access transmission
tariff (OATT) to be charged by PJM. Management believes that the FERC
will grant permission for the deferred RTO costs to be amortized and
included in the OATT. Whether the amortized costs will be fully
recoverable depends upon the state regulatory commissions' treatment of
AEP East companies' portion of the OATT at the time they join PJM.
Presently, retail rates are frozen or capped and cannot be increased for
retail customers of CSPCo, I&M and OPCo. APCo's base rates are capped
with no changes possible prior to January 1, 2004. AEP intends to file
an application with FERC seeking permission to delay the amortization of
the deferred RTO formation/integration costs until they are recoverable
from all users of the transmission system including retail customers.
Management is unable to predict the timing of when AEP will join PJM and
if upon joining PJM whether FERC will grant a delay of recovery until
the rate caps and freezes end. If 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). Management intends to seek
recovery of the deferred RTO formation/integration costs and project
implementation cost reimbursements, if incurred. If the FERC ultimately
decides not to approve a delay or the state commissions deny recovery,
future results of operations and cash flows could be adversely affected.
FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo,
I&M, KPCo and OPCo
On July 23, 2003, the FERC issued an order directing PJM and the Midwest
ISO to make compliance filings for their respective Open Access
Transmission Tariffs to eliminate, by November 1, 2003, the Regional
Through and Out Rates (RTOR) on transactions where the energy is
delivered within the Midwest ISO and PJM regions (RTO Footprint). In
October 2003, the FERC postponed the November 1, 2003 deadline to
eliminate RTOR. The elimination of the RTORs will reduce the
transmission service revenues collected by the RTOs and thereby reduce
the revenues received by transmission owners under the RTOs' revenue
distribution protocols. The order provided that affected Transmission
Owners could file to offset the elimination of these revenues by
increasing rates or utilizing a transitional rate mechanism to recover
lost revenues that result from the elimination of the RTORs. The FERC
also found that the RTOR of some of the former Alliance RTO Companies,
including AEP, may be unjust, unreasonable, and unduly discriminatory or
preferential for energy delivered in the Midwest ISO/PJM regions. FERC
has initiated an investigation and hearing in regard to these rates. AEP
made a filing with the FERC supporting the justness and reasonableness
of its rates in August 2003 and made a joint filing with unaffiliated
utilities, on October 14, 2003, proposing a regional revenue replacement
mechanism for the lost revenues, in the event that FERC eliminates AEP's
ability to collect RTOR in the RTO Footprint. Also on October 14, 2003,
FERC issued an order delaying the November 1, 2003 elimination of RTORs
without setting a new date for such elimination. The AEP East companies
received approximately $150 million of RTOR revenues from transactions
delivering energy to customers in the RTO Footprint for the twelve
months ended June 30, 2003. At this time, management is unable to
predict the ultimate outcome of this investigation, or its impact on
future results of operations, cash flows and financial condition.
Indiana Fuel Order - Affecting I&M
On July 17, 2003, I&M filed a fuel adjustment clause application
requesting authorization to implement the fixed fuel adjustment charge
(fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage)
for electric service for the billing months of October 2003 through
February 2004, and for approval of a new fuel cost adjustment credit for
electric service to be applicable during the March 2004 billing month.
On August 27, 2003, the IURC issued an order approving the requested
fixed fuel adjustment charge for October 2003 through February 2004. The
order further stated that certain parties must negotiate the appropriate
action on fuel to commence on March 1, 2004. The IURC deferred ruling on
the March 2004 factor until after January 1, 2004.
Michigan 2004 Fuel Recovery Plan - Affecting I&M
The MPSC's December 16, 1999 order approved a Settlement Agreement
regarding the extended outage of the Cook Plant and fixed I&M Power
Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers
rate areas through December 2003. In accordance with the settlement,
PSCR Plan cases were not required to be filed through the 2003 plan
year. For the 2004 plan year, I&M was required to file a PSCR Plan case
with the MPSC by September 30, 2003. I&M filed its 2004 PSCR Plan with
the MPSC on September 30, 2003 seeking new fuel and power supply
recovery factors to be effective in 2004.
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
------------------------------------------
As discussed in the 2002 Annual Report (as updated by the Current Report
on Form 8-K dated May 14, 2003), retail customer choice began in four of
the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which the AEP domestic electric utility companies operate.
The following paragraphs discuss significant events occurring in 2003
related to customer choice and industry restructuring.
Ohio Restructuring - Affecting CSPCo and OPCo
On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
Users-Ohio and American Municipal Power-Ohio filed a complaint with the
PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
regarding implementation of their transition plan and violated other
applicable law by failing to participate in an RTO.
The complainants seek, among other relief, an order from the PUCO:
o suspending collection of transition charges by CSPCo and OPCo
until transfer occurred
o requiring the pricing of standard offer electric generation
effective January 1, 2006 at the market price used by CSPCo and
OPCo in their 1999 transition plan filings to estimate
transition costs and
o imposing a $25,000 per company forfeiture for each day AEP
fails to comply with its commitment to transfer control of
transmission assets to an RTO
Due to the FERC's reversal of its previous approval of our RTO filings
and state legislative and regulatory developments, CSPCo and OPCo have
been delayed in the implementation of their RTO participation plans. We
continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo
filed an application with the PUCO for approval of the transfer of
functional control over certain of their transmission facilities to PJM.
In February 2003, the PUCO consolidated the June complaint with our
December application. CSPCo's and OPCo's motion to dismiss the complaint
has been denied by the PUCO and the PUCO affirmed that ruling in
rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC
and elsewhere." Management is currently unable to predict the timing of
the AEP East companies' (including CSPCo and OPCo) participation in PJM,
or the outcome of these proceedings before the PUCO.
On March 20, 2003, the PUCO commenced a statutorily required
investigation concerning the desirability, feasibility and timing of
declaring retail ancillary, metering or billing and collection service,
supplied to customers within the certified territories of electric
utilities, a competitive retail electric service. The PUCO sent out a
list of questions and set June 6, 2003 and July 7, 2003, as the dates
for initial responses and replies, respectively. CSPCo and OPCo filed
comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this
proceeding.
The Ohio Act provides for a Market Development Period (MDP) during which
retail customers can choose their electric power suppliers or receive
Default Service at frozen generation rates from the incumbent utility.
The MDP began on January 1, 2001 and is scheduled to terminate no later
than December 31, 2005. The PUCO may terminate the MDP for one or more
customer classes before that date if it determines either that effective
competition exists in the incumbent utility's certified territory or
that there is a twenty percent switching rate of the incumbent utility's
load by customer class. Following the MDP, retail customers will receive
distribution and transmission service from the incumbent utility whose
distribution rates will be approved by the PUCO and whose transmission
rates will be approved by the FERC. Retail customers will continue to
have the right to choose their electric power suppliers or receive
Default Service, which must be offered by the incumbent utility at
market rates. The PUCO has circulated a draft of proposed rules but has
not yet identified the method by which it will determine market rates
for Default Service following the MDP.
As provided in stipulation agreements approved by the PUCO, CSPCo and
OPCo are deferring customer choice implementation costs that are in
excess of $20 million per company. The agreements provide for the
deferral of these costs as a regulatory asset until the company's next
distribution base rate case. At September 30, 2003, CSPCo has incurred
$31 million and deferred $11 million and OPCo has incurred $34 million
and deferred $14 million of such costs. Recovery of these regulatory
assets will be subject to PUCO review in each company's next Ohio filing
for new distribution rates. Approved rates will not become effective
prior to 2009 for CSPCo and 2008 for OPCo. Management believes that the
customer choice implementation costs were prudently incurred and the
deferred amounts should be recoverable in future rates. If the PUCO
determines that any of the deferred costs are unrecoverable, it would
have an adverse impact on future results of operations and cash flows.
Texas Restructuring - Affecting SWEPCo, TCC and TNC
On January 1, 2002, customer choice of electricity supplier began in the
ERCOT area of Texas. Customer choice has been delayed in other areas of
Texas including the SPP area in which SWEPCo operates. In May 2003, the
PUCT approved a stipulation that delays competition in the SPP area
until at least January 1, 2007.
A 2004 true-up proceeding will determine the amount and recovery of
stranded plant costs as of December 31, 2001 including certain
environmental costs incurred by May 1, 2003, final deferred fuel
balance, net generation-related regulatory assets, unrefunded
accumulated excess earnings, excess of price-to-beat revenues over
market prices subject to certain conditions and limitations (Retail
clawback), a true-up of the power costs used in the PUCT's ECOM model
for 2002 and 2003 to reflect actual market prices determined through
legislatively-mandated capacity auctions (wholesale capacity auction
true-up) and other restructuring true-up issues.
The Texas Legislation provides for an earnings test each year from 1999
through 2001 and requires PUCT approval of the annual earnings test
calculation. TCC, TNC and SWEPCo had appealed the PUCT's Final 2000
Earnings Test Order to the Texas Court of Appeals. In August 2003, the
Appeals Court reversed the PUCT order and the district court judgment
affirming it and remanded the controversy back to the PUCT for
proceedings consistent with the Appeals Court's decision. The PUCT
requested rehearing of the Court of Appeal's decision. Our appeal of the
same issue from the PUCT's 2001 Order is pending before the District
Court. Since an expense and regulatory liability had been accrued in
prior years in compliance with the PUCT Final Orders, the companies
reversed a portion of their regulatory liability and credited
amortization expense during the third quarter of 2003. Pre-tax amounts
by company were $5.1 million for TCC, $2.6 million for TNC and $1.1
million for SWEPCo.
The Texas Legislation provides for the affiliated PTB REP to refund to
its transmission and distribution (T&D) utility the excess of the PTB
revenues over market prices (subject to certain conditions and a
limitation of $150 per customer). This is the retail clawback. The
retail clawback regulatory liability is to be included in the 2004
true-up proceedings and netted against other true-up adjustments. If 40%
of the load for the residential or small commercial classes is served by
competitive REPs, the retail clawback is not applicable for that class
of customer. In July 2003, TCC and TNC filed to notify the PUCT that
competitive REPs serve over 40% of the load in the small commercial
class. On August 21, 2003, the PUCT dismissed these filings and ruled
that TCC and TNC should refile no sooner than September 22, 2003 in
order to establish the required notice period. TCC and TNC refiled in
late September 2003. In October 2003, the PUCT Staff recommended
approval of TCC's application and denial of TNC's application. The PUCT
Staff determined that only 39.9% of TNC's small commercial customers
were served by competitive REPs as of the end of August 2003. If the
PUCT denies TNC's application, TNC will likely meet the 40% threshold in
September 2003 and refile its application. AEP had accrued a regulatory
liability of approximately $9 million for the small commercial retail
clawback on its REP's books. If the PUCT certifies that TCC and/or TNC
have reached the 40% threshold, the regulatory liability would no longer
be required for the small commercial class and could be reversed.
The Texas Legislation allows for several alternative methods to be used
to value stranded generation assets in the 2004 true-up proceeding
including the sale or exchange of generation assets, stock valuation
methods or the use of an ECOM model for nuclear generation assets. TCC
is the only AEP subsidiary that has stranded costs under the Texas
Legislation.
In the fourth quarter of 2002, TCC decided to determine the market value
of its generating assets through the sale of those assets for purposes
of determining stranded costs for the 2004 true-up proceeding. In
December 2002, TCC filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. The
amount of stranded costs under this market valuation methodology will be
the amount by which the book value of TCC's generating assets, including
regulatory assets and liabilities that were not securitized, exceeds the
market value of the generation assets as measured by the net proceeds
from the sale of the assets. It is anticipated that any such sale will
result in significant stranded costs for purposes of TCC's 2004 true-up
proceeding. The filing included a request for the PUCT to issue a
declaratory order that TCC's 25.2% ownership interest in its nuclear
plant, STP, can be sold to establish its market value for determining
stranded plant costs. Intervenors to this proceeding, including the PUCT
Staff, made filings to dismiss TCC's filing claiming that the PUCT does
not have the authority to issue such a declaratory order. The
intervenors also argued that the proper time to address the sales
process is after the plants are sold during the 2004 true-up proceeding.
Since the closing process for the plants sold is not expected to be
completed before mid-2004, TCC requested that its 2004 true-up
proceeding be scheduled after completion of the divestiture of its
generating assets.
In March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address allowable valuation methods for
the nuclear asset in a rulemaking proceeding. The PUCT approved a rule,
in May 2003, which allows the market value obtained by selling nuclear
assets to be used in determining stranded costs. The PUCT dismissed
TCC's request to certify its proposed divestiture plan; therefore its
divestiture plan will be subject to a review in the 2004 true-up
proceeding. The PUCT adopted a rule regarding the timing of the 2004
true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing
in September 2004 or 60 days after the completion of the sale of TCC's
generation assets, if later.
Texas Legislation also requires that electric utilities and their
affiliated power generation companies (PGC) sell at auction in 2002 and
2003 at least 15% of the PGC's Texas jurisdictional installed generation
capacity in order to promote competitiveness in the wholesale market
through increased availability of generation. Actual market power prices
received in the state mandated auctions will replace the PUCT's earlier
estimates of those market prices for 2002 and 2003 used in the ECOM
model to calculate the wholesale capacity auction true-up adjustment for
TCC for the 2004 true-up proceeding.
The decision to determine stranded costs by selling TCC's generating
plants and the expectation that the sales price would produce a
significant loss/stranded cost instead of using the PUCT's ECOM model
negative stranded cost estimate, enabled TCC to record in 2002 a $262
million regulatory asset and related revenues which represents the
quantifiable amount of the wholesale capacity auction true-up for the
year 2002. Through September 30, 2003, TCC recorded an additional $169
million regulatory asset and related revenues for wholesale capacity
auction true-up. Prior to the decision to pursue a sale of TCC's
generating assets, the PUCT's negative ECOM estimate prohibited the
recognition of the regulatory assets and revenues, as they can not be
recovered unless there are stranded costs. However, in March 2003, the
Texas Court of Appeals ruled that under the restructuring legislation,
other 2004 true-up items including the wholesale capacity auction
true-up regulatory asset, could be recovered regardless of the level of
stranded plant costs.
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.
When the plant divestitures and the 2004 true-up proceeding are
completed, TCC will file to recover PUCT-approved stranded costs and
other true-up amounts that are in excess of current securitized amounts
plus a carrying charge through a non-bypassable competition transition
charge in rates of the regulated T&D utility. In addition, TCC may seek
to securitize certain of the approved stranded plant costs and
regulatory assets, not previously recovered through the non-bypassable
transition charge. The annual costs of securitization are recovered
through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.
In the event TCC and TNC are unable, after the 2004 true-up proceeding,
to recover all or a portion of their generation-related regulatory
assets, unrecovered fuel balances, stranded plant 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.
Arkansas Restructuring - Affecting SWEPCo
In February 2003, Arkansas repealed customer choice legislation
originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
reapplied SFAS 71 regulatory accounting, which had been discontinued in
1999. The reapplication of SFAS 71 had an insignificant effect on
results of operations and financial condition. As a result of reapplying
SFAS 71, derivative contract gains/losses for transactions within AEP's
traditional marketing area allocated to Arkansas will not affect income
until settled. That is, such positions will be recorded on the balance
sheet as either a regulatory asset or liability until realized.
West Virginia Restructuring - Affecting APCo
APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
first quarter of 2003 after new developments during the quarter prompted
an analysis of the probability of restructuring becoming effective.
In 2000, the WVPSC issued an order approving an electricity
restructuring plan, which the WV Legislature approved by joint
resolution. The joint resolution provided that the WVPSC could not
implement the plan until the WV legislature made tax law changes
necessary to preserve the revenues of state and local governments.
In the 2001 and 2002 legislative sessions, the WV Legislature failed to
enact the required legislation that would allow the WVPSC to implement
the restructuring plan. Due to this lack of legislative activity, the
WVPSC closed two proceedings related to electricity restructuring during
the summer of 2002.
In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, legislation enacted in March 2003
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
restructuring in WV was no longer probable and confirmed facts relating
to the WVPSC's jurisdiction and rate authority over APCo's WV
generation. APCo has concluded that deregulation of the WV generation
business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.
Reapplying SFAS 71 in WV had an insignificant effect on results of
operations and financial condition. As a result, derivative contract
gains/losses related to transactions within AEP's traditional marketing
area allocated to WV will not affect income until settled. That is, such
positions will be recorded on the balance sheet as either a regulatory
asset or liability until realized. Positions outside AEP's traditional
marketing area will continue to be marked-to-market.
5. COMMITMENTS AND CONTINGENCIES
-----------------------------
Nuclear Plant Outages - Affecting I&M and TCC
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. TCC's 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 I&M's 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.
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo,
I&M, and OPCo
As discussed in Note 9 of the Combined Notes to Financial Statements 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 modified certain units at coal-fired
generating plants in violation of the Clean Air Act. The Federal EPA
filed complaints against AEP subsidiaries in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain
special interest groups was consolidated with the Federal EPA case. The
alleged modification of the generating units occurred over a 20-year
period.
Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might
be triggered and the plant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant. The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997). In
2001, the District Court ruled claims for civil penalties based on
activities that occurred more than five years before the filing date of
the complaints cannot be imposed. There is no time limit on claims for
injunctive relief.
On August 7, 2003, the District Court issued a decision following a
liability trial in a case pending in the Southern District of Ohio
against Ohio Edison Company, an unaffiliated utility. The District Court
held that replacements of major boiler and turbine components that are
infrequently performed at a single unit, that are performed with the
assistance of outside contractors, that are accounted for as capital
expenditures, and that require the unit to be taken out of service for a
number of months are not "routine" maintenance, repair, and replacement.
The District Court also held that a comparison of past actual emissions
to projected future emissions must be performed prior to any non-routine
physical change in order to evaluate whether an emissions increase will
occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all
of the challenged activities in that case were not routine, and that the
changes resulted in significant net increases in emissions for certain
pollutants. A remedy trial is scheduled for April 2004.
Management believes that the Ohio Edison decision fails to properly
evaluate and apply the applicable legal standards. The facts in the AEP
case also vary widely from plant to plant. Further, the Ohio Edison
decision is limited to liability issues, and provides no insight as to
the remedies that might ultimately be ordered by the Court.
On August 26, 2003, the District Court for the Middle District of South
Carolina issued a decision on cross-motions for summary judgment prior
to a liability trial in a case pending against Duke Energy Corporation,
an unaffiliated utility. The District Court denied all the pending
motions, but set forth the legal standards that will be applied at the
trial in that case. The District Court determined that Federal EPA bears
the burden of proof on the issue of whether a practice is "routine
maintenance, repair, or replacement" and on whether or not a
"significant net emissions increase" results from a physical change or
change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the
relevant source category" in determining if it is "routine." Further,
the Federal EPA must calculate emissions by determining first whether a
change in the maximum achievable hourly emission rate occurred as a
result of the change, and then must calculate any change in annual
emissions holding hours of operation constant before and after the
change.
On June 24, 2003, the United States Court of Appeals for the 11th
Circuit issued an order invalidating the administrative compliance order
issued by the Federal EPA to the Tennessee Valley Authority for similar
alleged violations. The 11th Circuit determined that the administrative
compliance order was not a final agency action, and that the enforcement
provisions authorizing the issuance and enforcement of such orders under
the Clean Air Act are unconstitutional.
On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group
(UARG), of which the AEP subsidiaries are members, to reopen petitions
for review of the 1980 and 1992 Clean Air Act rulemakings that are the
basis for the Federal EPA claims in the AEP case and other related
cases. On August 4, 2003, UARG filed a motion to separate and expedite
review of their challenges to the 1980 and 1992 rulemakings from other
unrelated claims in the consolidated appeal. The Circuit Court denied
that motion on September 30, 2003. The central issue in these petitions
concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement
actions. A decision by the D. C. Circuit Court could significantly
impact further proceedings in the AEP case.
On August 27, 2003, the Administrator of the Federal EPA signed a final
rule that defines "routine maintenance repair and replacement" to
include "functionally equivalent equipment replacement." Under the new
final rule, replacement of a component within an integrated industrial
operation (defined as a "process unit") with a new component that is
identical or functionally equivalent will be deemed to be a "routine
replacement" if the replacement does not change any of the fundamental
design parameters of the process unit, does not result in emissions in
excess of any authorized limit, and does not cost more than twenty
percent of the replacement cost of the process unit. The new rule is
intended to have prospective effect, and will become effective in
certain states 60 days after October 27, 2003, the date of its
publication in the Federal Register, and in other states upon completion
of state processes to incorporate the new rule into state law. On
October 27, 2003 twelve states, the District of Columbia and several
cities filed an action in the United States Court of Appeals for the
District of Columbia Circuit seeking judicial review of the new rule.
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.
In December 2000, Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement
with the Federal EPA and other parties to settle litigation regarding
generating plant emissions under the Clean Air Act. Negotiations are
continuing between the parties in an attempt to reach final settlement
terms. Cinergy's settlement could impact the operation of Zimmer Plant
and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
respectively, by CSPCo). Until a final settlement is reached, CSPCo will
be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
NOx Reductions - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo
and TCC
The Federal EPA issued a NOx Rule requiring substantial reductions in
NOx emissions in a number of eastern states, including certain states in
which the AEP System's generating plants are located. The NOx Rule has
been upheld on appeal. The compliance date for the NOx Rule is May 31,
2004.
In 2000, the Federal EPA also adopted a revised rule (the Section 126
Rule) granting petitions filed by certain northeastern states under the
Clean Air Act. The rule imposes emissions reduction requirements
comparable to the NOx Rule beginning May 1, 2003, for most of our
coal-fired generating units. Affected utilities, including certain AEP
operating companies, petitioned the D.C. Circuit Court to review the
Section 126 Rule.
After review, the D.C. Circuit Court instructed the Federal EPA to
justify the methods it used to allocate allowances and project growth
for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and
other utilities requested that the D.C. Circuit Court vacate the Section
126 Rule or suspend its May 2003 compliance date. In 2001, the D.C.
Circuit Court issued an order tolling the compliance schedule until the
Federal EPA responds to the Court's remand. On April 30, 2002, the
Federal EPA announced that May 31, 2004 is the compliance date for the
Section 126 Rule. The Federal EPA published a notice in the Federal
Register on May 1, 2002 advising that no changes in the growth factors
used to set the NOx budgets were warranted. In June 2002, AEP
subsidiaries joined other utilities and industrial organizations in
seeking a review of the Federal EPA's actions in the D.C. Circuit Court.
This action is pending.
In 2000, the Texas Commission on Environmental Quality adopted rules
requiring significant reductions in NOx emissions from utility sources,
including TCC and SWEPCo. The compliance requirements began in May 2003
for TCC and begin in May 2005 for SWEPCo.
We are installing a variety of emission control technologies to reduce
NOx emissions to comply with the applicable state and Federal NOx
requirements. This includes selective catalytic reduction (SCR)
technology on certain units and other combustion control technologies
on a larger number of units. During 2001, 2002 and 2003, SCR technology
commenced operations on units of Gavin, Amos, Mountaineer, Big Sandy
and Cardinal plants. Construction of SCR technology at certain other
AEP generating units continues. Other combustion control technologies
have been installed and commenced operation on a number of units
across the AEP System and additional units will be equipped with these
technologies.
Our NOx compliance plan is a dynamic plan that is continually reviewed
and revised as new information becomes available on the performance of
installed technologies and the cost of planned technologies. Certain
compliance steps may or may not be necessary as a result of this new
information. Consequently, the plan has a range of possible outcomes.
Current estimates indicate that AEP's compliance with the NOx Rule, the
Texas Commission on Environmental Quality rule and the Section 126 Rule
could result in required capital expenditures in the range of $1.3
billion to $1.7 billion, of which $1 billion has been spent through
September 30, 2003. Estimated compliance cost ranges and amounts spent
by subsidiaries are as follows:
Estimated Amount
Compliance Costs Spent
---------------- -----
(in millions)
AEGCo $28 $7
APCo 464 283
CSPCo 87 68
I&M 39 12
KPCo 180 179
OPCo 531-860 431
SWEPCo 35 23
TCC 5 5
Since compliance costs cannot be estimated with certainty, 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 and 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.
Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
Texas Commercial Energy, LLP (TCE), a Texas REP, has filed a lawsuit in
federal District Court in Corpus Christi, Texas against AEP and four AEP
subsidiaries, including TCC and TNC, certain unaffiliated energy
companies and ERCOT. The action alleges violations of the Sherman
Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary
duty, breach of contract, civil conspiracy and negligence. The
allegations, not all of which are made against the AEP companies, range
from anticompetitive bidding to withholding power. TCE alleges that
these activities resulted in price spikes requiring TCE to post
additional collateral and ultimately forced it into bankruptcy when it
was unable to raise prices to its customers due to fixed price
contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court
costs. This case is in the initial pleading stage. We have filed a
Motion to Dismiss. The Court has set a hearing on the Motion to Dismiss
for January 2004. Management believes that the claims against AEP and
its subsidiaries are without merit. We intend to vigorously defend
against the claims.
FERC Proposed Standard Market Design - Affecting AEP System
In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking which sought to standardize the structure and
operation of wholesale electricity markets across the country. Key
elements of FERC's proposal included standard rules and processes for
all users of the electricity transmission grid, new transmission rules
and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC issued a
white paper on the proposal in April 2003, in response to the numerous
comments FERC received on its proposal. Until the rule is finalized,
management cannot predict its effect on cash flows and results of
operations.
FERC Proposed Security Standards - Affecting AEP System
As part of the SMD proposed rulemaking, in July 2002, FERC published for
comment proposed security standards. These standards were intended to
ensure that all market participants would have a basic security program
that would effectively protect the electric grid and related market
activities. As proposed, these standards would apply to AEP's power
transmission systems, distribution systems and related areas of
business. The proposed standards have not been adopted. Subsequently, in
2002, the North American Electric Reliability Council (NERC), with
FERC's support, developed a new set of standards to address industry
compliance. These new standards closely parallel the initial, proposed
FERC standards in both content and compliance time frames, and were
approved by the NERC ballot body in June 2003. We have developed
financial requirements for security implementation and compliance with
these NERC standards, the costs of which are not expected to be material
to our future results of operations and cash flows.
6. GUARANTEES
----------
There are no liabilities recorded for guarantees entered into prior to
December 31, 2002 by AEP's registrant subsidiaries in accordance with
FIN 45. There are certain liabilities recorded for guarantees entered
into subsequent to December 31, 2002. These liabilities are immaterial.
There is no collateral held in relation to any guarantees and there is
no recourse to third parties in the event any guarantees are drawn
unless specified below.
Letters of Credit
Certain AEP subsidiaries have entered into standby letters of credit
(LOC) with third parties. These LOCs cover gas and electricity trading
contracts, construction contracts, insurance programs, security
deposits, debt service reserves, drilling funds and credit enhancements
for issued bonds. All of these LOCs were issued by an AEP subsidiary in
the subsidiaries' ordinary course of business. At September 30, 2003,
the maximum future payments of all the LOCs are approximately $181
million with maturities ranging from September 30, 2003 to January 2011.
Included in these amounts is TCC's LOC for credit enhancement of
approximately $40.9 million with a maturity date of November 2003. As
the parent of all these subsidiaries, AEP holds all assets of the
subsidiaries as collateral. There is no recourse to third parties in the
event these letters of credit are drawn.
SWEPCo
In connection with reducing the cost of the lignite mining contract for
its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
conditions, to assume the obligations under a revolving credit
agreement, capital lease obligations, and term loan payments of the
mining contractor, Sabine Mining Company (Sabine). In the event Sabine
defaults under any of these agreements, SWEPCo's total future maximum
payment exposure is approximately $60 million with maturity dates
ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At September 30,
2003, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.
On July 1, 2003, SWEPCo consolidated Sabine due to the application of
FIN 46 (see Note 2). Upon consolidation, SWEPCo recorded the assets and
liabilities of Sabine ($77.8 million). Also, after consolidation, SWEPCo
currently records all expenses (depreciation, interest and other
operation expense) of Sabine and eliminates Sabine's revenues against
SWEPCo's fuel expenses. There is no cumulative effect of an accounting
change recorded as a result of the requirement to consolidate, and there
is no change in net income due to the consolidation of Sabine.
Indemnifications and Other Guarantees
AEP subsidiaries enter into several types of contracts, which would
require indemnifications. Typically these contracts include, but are not
limited to, sale agreements, lease agreements, purchase agreements and
financing agreements. Generally these agreements may include, but are
not limited to, indemnifications around certain tax, contractual and
environmental matters. With respect to sale agreements, exposure
generally does not exceed the sale price. The subsidiaries cannot
estimate the maximum potential exposure for any of these
indemnifications entered into prior to December 31, 2002 due to the
uncertainty of future events. In the first nine months of 2003, AEP's
registrant subsidiaries entered into sale agreements which included
indemnifications with a maximum exposure that was not significant for
any individual registrant subsidiary. There are no material liabilities
recorded for any indemnifications entered into during the first nine
months of 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.
AEP and its subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At September 30, 2003, the maximum potential loss
by subsidiary for these lease agreements assuming the fair market value
of the equipment is zero at the end of the lease term is as follows:
Maximum Potential Loss
Subsidiary (in millions)
---------- ----------------------
APCo $ 1
CSPCo 1
I&M 2
KPCo 1
OPCo 3
PSO 4
SWEPCo 4
TCC 6
TNC 2
See Note 8 "Leases" for disclosure of lease residual value guarantees.
7. BUSINESS SEGMENTS
-----------------
All of AEP's registrant subsidiaries have one reportable segment. The
one reportable segment is a vertically integrated electricity
generation, transmission and distribution business except AEGCo, an
electricity generation business. All of the registrants' other
activities are insignificant. The registrant subsidiaries operations are
managed on an integrated basis because of the substantial impact of
bundled cost-based rates and regulatory oversight on the business
process, cost structures and operating results.
8. LEASES
------
OPCo has entered into an agreement with JMG Funding LLP (JMG), an
unrelated special purpose entity. JMG has a capital structure of which
3% is equity from investors with no relationship to AEP or any of its
subsidiaries and 97% is debt from commercial paper, pollution control
bonds and other bonds. JMG was formed to design, construct and lease the
Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
and leases it to OPCo. The lease is accounted for as an operating lease.
Payments under the operating lease are based on JMG's cost of financing
(both debt and equity) and include an amortization component plus the
cost of administration. OPCo and AEP do not have an ownership interest
in JMG and do not guarantee JMG's debt.
On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46.
Upon consolidation, OPCo recorded the assets and liabilities of JMG
($469.6 million). OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's
operating lease expenses. There was no cumulative effect of an
accounting change recorded as a result of our requirement to consolidate
JMG, and there was no change in net income due to the consolidation of
JMG.
At any time during the lease, OPCo has the option to purchase the Gavin
Scrubber for the greater of its fair market value or adjusted
acquisition cost (equal to the unamortized debt and equity of JMG) or
sell the Gavin Scrubber. The initial 15-year lease term is
non-cancelable. At the end of the initial term, OPCo can renew the
lease, purchase the Gavin Scrubber (terms previously mentioned), or sell
the Gavin Scrubber. In case of a sale at less than the adjusted
acquisition cost, OPCo must pay the difference to JMG.
9. FINANCING AND RELATED ACTIVITIES
--------------------------------
Long-term debt and other securities issuances and retirements during the
first nine months of 2003 were:
Principal Interest Due
Company Type of Debt Amount Rate Date
------- ------------ --------- -------- ----
(in millions) (%)
Issuances:
APCo Senior Unsecured Notes $200 3.60 2008
APCo Senior Unsecured Notes 200 5.95 2033
APCo Installment Purchase
Contracts 100 5.50 2022
CSPCo Senior Unsecured Notes 250 5.50 2013
CSPCo Senior Unsecured Notes 250 6.60 2033
KPCo Senior Unsecured Notes 75 5.625 2032
OPCo Senior Unsecured Notes 250 5.50 2013
OPCo Senior Unsecured Notes 250 6.60 2033
OPCo Senior Unsecured Notes 225 4.85 2014
OPCo Senior Unsecured Notes 225 6.375 2033
PSO Senior Unsecured Notes 150 4.85 2010
SWEPCo Senior Unsecured Notes 100 5.375 2015
SWEPCo Secured Note of Subsidiary 44 4.47 2011
TCC Senior Unsecured Notes 150 3.00 2005
TCC Senior Unsecured Notes 100 Variable 2005
TCC Senior Unsecured Notes 275 5.50 2013
TCC Senior Unsecured Notes 275 6.65 2033
TNC Senior Unsecured Notes 225 5.50 2013
Principal Interest Due
Company Type of Debt Amount Rate Date
------- ------------ --------- ------- -----
(in millions) (%)
Retirements:
APCo First Mortgage Bonds $ 70 8.50 2022
APCo First Mortgage Bonds 30 7.80 2023
APCo First Mortgage Bonds 20 7.15 2023
APCo Installment Purchase
Contracts 10 7.875 2013
APCo Installment Purchase
Contracts 40 6.85 2022
APCo Installment Purchase
Contracts 50 6.60 2022
APCo Senior Unsecured Notes 100 7.20 2038
APCo Senior Unsecured Notes 100 7.30 2038
APCo Senior Unsecured Notes 125 Variable 2003
CSPCo First Mortgage Bonds 2 8.70 2022
CSPCo First Mortgage Bonds 15 8.55 2022
CSPCo First Mortgage Bonds 14 8.40 2022
CSPCo First Mortgage Bonds 13 8.40 2022
CSPCo First Mortgage Bonds 13 6.80 2003
CSPCo First Mortgage Bonds 26 6.55 2004
CSPCo First Mortgage Bonds 26 6.75 2004
CSPCo First Mortgage Bonds 40 7.90 2023
CSPCo First Mortgage Bonds 33 7.75 2023
CSPCo First Mortgage Bonds 25 6.60 2003
I&M First Mortgage Bonds 75 8.50 2022
I&M First Mortgage Bonds 15 7.35 2023
I&M Junior Debentures 40 8.00 2026
I&M Junior Debentures 125 7.60 2038
KPCo Junior Debentures 40 8.72 2025
OPCo First Mortgage Bonds 30 6.75 2003
PSO First Mortgage Bonds 35 6.25 2003
PSO First Mortgage Bonds 65 7.25 2003
SWEPCo First Mortgage Bonds 55 6.625 2003
SWEPCo Secured Note of Subsidiary 2 4.47 2011
SWEPCo Notes Payable 1 Variable 2008
TCC First Mortgage Bonds 18 7.50 2023
TCC First Mortgage Bonds 16 6.875 2003
TCC Securitization Bonds 51 3.54 2005
In addition to the transactions reported in the table above, the
following table lists intercompany retirements of debt due to AEP:
Principal Interest Due
Company Type of Debt Amount Rate Date
------- ------------ --------- -------- -----
(in millions) (%)
Retirements:
CSPCo Notes Payable $160 6.501 2006
KPCo Notes Payable 15 4.336 2003
OPCo Notes Payable 240 6.501 2006
OPCo Notes Payable 60 4.336 2003
LINES OF CREDIT AND RELATED SHORT-TERM BORROWINGS
-------------------------------------------------
The AEP System Corporate Borrowing Program is the funding mechanism AEP
uses to meet the short-term cash requirements of the system. The
Corporate Borrowing Program consists of two primary funding groups: the
AEP system Utility Money Pool, used by regulated companies, and the AEP
system Non-Utility Money Pool, used by non-regulated companies. The AEP
system Corporate Borrowing Program operates consistent with the terms
and conditions outlined by the SEC. AEP has authority from the SEC
through March 31, 2006 for short-term borrowings sufficient to fund the
utility money pool and the non-utility money pool as well as its own
requirements in an amount not to exceed $7.2 billion. Utility money pool
participants include AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC (domestic utility companies). The following are the
SEC-authorized limits for short-term borrowings for the domestic utility
companies as of September 30, 2003:
Authorized
----------
(in millions)
AEP Generating $125
AEP Texas Central (a) 600
AEP Texas North (a) 275
Appalachian Power 600
Columbus Southern Power (a) 300
Indiana Michigan Power 500
Kentucky Power 200
Ohio Power (a) 250
Public Service Company of
Oklahoma 300
Southwestern Electric Power 350
(a) Short term borrowing limits for these domestic utility companies are
reduced by long-term debt issued commencing with the SEC order dated
December 18, 2003, which authorized financing transactions through March
31, 2006.
CONTROLS AND PROCEDURES
During the third quarter of 2003, AEP's management, including the principal
executive officer and principal financial officer, evaluated AEP'sdisclosure
controls and procedures related to the recording, processing, summarization
and reporting of information in AEP's periodic reports that it files with
the SEC. These disclosure controls and procedures have been designed to
ensure that (a) material information relating to AEP, including its
consolidated subsidiaries, is made known to AEP's management, including
these officers, by other employees of AEP and its subsidiaries, and (b) this
information is recorded, processed, summarized, evaluated and reported, as
applicable, within the time periods specified in the SEC's rules and forms.
AEP's controls and procedures can only provide reasonable, not absolute,
assurance that the above objectives have been met.
As of September 30, 2003, these officers concluded that the disclosure
controls and procedures in place provide reasonable assurance that the
disclosure controls and procedures can accomplish their objectives. AEP
continually strives to improve its disclosure controls and procedures to
enhance the quality of its financial reporting and to maintain dynamic
systems that change as conditions warrant.
There have not been any changes in AEP's internal controls over financial
reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the
Exchange Act) during the third quarter of 2003 that have materially
affected, or are reasonably likely to materially affect, AEP's internal
control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
------------------
For a discussion of material legal proceedings, see Note 6 to AEP's
consolidated financial statements and Note 5 to AEP's registrant
subsidiaries' respective financial statements, both entitled
Commitments and Contingencies, incorporated herein by reference.
Item 5. Other Information.
------------------
NONE
Item 6. Exhibits and Reports on Form 8-K.
---------------------------------
(a) Exhibits:
---------
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 12 - Computation of Consolidated Ratio of Earnings
to Fixed Charges.
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Exhibit 31.1 - Certification of Chief Executive Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 31.2 - Certification of Chief Financial Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.1 - Certification of Chief Executive Officer
Pursuant to Section 1350 of Chapter 63 of Title 18 of the
United States Code.
Exhibit 32.2 - Certification of Chief Financial Officer
Pursuant to Section 1350 of Chapter 63 of Title 18 of the
United States Code.
(b) Reports on Form 8-K:
--------------------
AEGCo, APCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC
The following reports on Form 8-K were filed during the quarter
ended September 30, 2003.
Company Reporting Date of Report Item Reported
----------------- -------------- --------------
AEP July 30, 2003 Item 7. Financial Statements And Exhibits
Item 9. Regulation FD Disclosure
OPCo July 8, 2003 Item 5. Other Events and Regulation FD Disclosure
Item 7. Financial Statements And Exhibits
PSO September 10, 2003 Item 5. Other Events and Regulation FD Disclosure
Item 7. Financial Statements And Exhibits
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Joseph M. Buonaiuto
-----------------------
Joseph M. Buonaiuto
Controller and
Chief Accounting Officer
AEP GENERATING COMPANY
AEP TEXAS CENTRAL COMPANY
AEP TEXAS NORTH COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/Joseph M. Buonaiuto
-----------------------
Joseph M. Buonaiuto
Controller and
Chief Accounting Officer
Date: November 12, 2003