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 MARCH 31,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.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) 223-1000
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 April 30, 2003 was 394,993,420.716-1000
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
For The Quarter Ended March 31,September 30, 2003
CONTENTS
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 of Results of Operations:
Analysis:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Financial Discussion and Analysis of Results of Operations A-1 - A-3A-19
Consolidated Financial Statements A-4A-20 - A-8A-25
Notes to Consolidated Financial Statements A-26 - A-57
AEP Generating Company:
Management's Narrative Financial Discussion and Analysis of Results of Operations B-1 - B-2
Financial Statements B-3B-2 - B-6B-5
AEP Texas Central Company and Subsidiaries:Subsidiary:
Management's Financial Discussion and Analysis of Results of Operations C-1 - C-4C-8
Consolidated Financial Statements C-5C-9 - C-9C-12
AEP Texas North Company:
Management's Narrative Financial Discussion and Analysis of Results of Operations D-1 - D-3D-6
Financial Statements D-4D-7 - D-8D-11
Appalachian Power Company and Subsidiaries:
Management's Financial Discussion and Analysis of Results of Operations E-1 - E-3E-7
Consolidated Financial Statements E-4E-8 - E-8E-12
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Financial Discussion and Analysis of Results of Operations F-1 - F-2F-6
Consolidated Financial Statements F-3F-7 - F-7F-11
Indiana Michigan Power Company and Subsidiaries:
Management's Financial Discussion and Analysis of Results of Operations G-1 - G-3G-6
Consolidated Financial Statements G-4G-7 - G-8G-11
Kentucky Power Company:
Management's Narrative Analysis of Results of Operations H-1 - H-2
Financial Statements H-3 - H-7
Ohio Power Company:
Management's Discussion and Analysis of Results of OperationsH-1 - H-6
Financial Statements H-7 - H-11
Ohio Power Company Consolidated:
Management's Financial Discussion and Analysis I-1 - I-3I-7
Consolidated Financial Statements I-4I-8 - I-8I-12
Public Service Company of Oklahoma and Subsidiary:Oklahoma:
Management's Narrative Financial Discussion and Analysis of Results of Operations J-1 - J-2
ConsolidatedJ-5
Financial Statements J-3J-6 - J-7J-10
Southwestern Electric Power Company and Subsidiaries:Consolidated:
Management's Financial Discussion and Analysis of Results of Operations K-1 - K-2K-6
Consolidated Financial Statements K-3K-7 - K-7
CombinedK-11
Notes to Respective Financial Statements L-1 - L-33
Item 2. Registrants' Combined Management's Discussion and Analysis of
Financial Condition, Accounting Policies and Other Matters M-1 - M-14
Item 3. Quantitative and Qualitative Disclosures About Risk Management Activities N-1 - N-13L-24
Item 4. Controls and Procedures O-1M-1
Part II. OTHER INFORMATION
Item 1. Legal Proceedings N-1
Item 5. Other Information P-1N-1
Item 6. Exhibits and Reports on Form 8-K P-1N-1
(a) ExhibitsExhibits: Exhibit 12 Exhibit 99.131.1
Exhibit 99.231.2 Exhibit 32.1 Exhibit
32.2
(b) Reports on Form 8-K
SIGNATURES Q-1
CERTIFICATIONS R-1 - R-4SIGNATURE 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.
iii
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............AProceeding 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..............................AEPAEGCo AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................AmericanAEP American Electric Power Company, Inc.
AEP Consolidated...................AEPConsolidated AEP and its majority owned consolidated subsidiaries.subsidiaries and consolidated affiliates.
AEP Credit.........................AEPCredit AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East companies.................APCo,companies APCo, CSPCo, I&M, KPCo and OPCo.
AEPR...............................AEPAEPES AEP Energy Services, Inc., a subsidiary of AEPR.
AEPR AEP Resources, Inc.
AEP System or the System...........TheSystem The American Electric Power System, an integrated electric utility system, owned and
operated by AEP's electric utility subsidiaries.
AEPSC..............................AmericanAEPSC American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool.....................AEPPool 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,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.........................JohnPlant John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo...............................AppalachianAPB 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................ArkansasCommission Arkansas Public Service Commission.
Buckeye............................BuckeyeBuckeye Buckeye Power, Inc., an unaffiliated corporation.
COLI...............................CorporateCOLI Corporate owned life insurance program.
Cook Plant.........................ThePlant The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo..............................ColumbusCSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW...............................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.........................CSWEnergy CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International..................CSWInternational CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court.................TheCourt The United States Court of Appeals for the District of Columbia Circuit.
DOE................................UnitedDOE United States Department of Energy.
ECOM...............................ExcessECOM Excess Cost Over Market.
EITF...............................TheEITF The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3..........................Recognition02-3 Emerging Issues Task Force Issue No. 02-3: Issues Involved in Accounting for Derivative
Contracts Held For Trading Purposes and Reporting of GainsContracts Involved in Energy Trading and
Losses on Energy Contracts under Issues No. 98-10 and
00-17.
ERCOT..............................TheRisk Management Activities.
ERCOT The Electric Reliability Council of Texas.
FASB...............................FinancialFASB Financial Accounting Standards Board.
Federal EPA........................UnitedEPA United States Environmental Protection Agency.
FERC...............................FederalFERC Federal Energy Regulatory Commission.
GAAP...............................GenerallyFIN 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&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR................................InterchangeICR Interchange Cost Reconstruction.
IRS................................InternalIRS Internal Revenue Service.
IURC...............................IndianaIURC Indiana Utility Regulatory Commission.
ISO................................IndependentISO Independent System Operator.
KPCo...............................KentuckyKPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC...............................KentuckyKPSC Kentucky Public Service Commission.
KWH................................Kilowatthour.
LIG................................LouisianaKWH Kilowatthour.
LIG Louisiana Intrastate Gas.Gas, an AEP subsidiary.
LPSC Louisiana Public Service Commission.
Michigan Legislation...............TheLegislation The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO...............................MidwestMISO Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR................................MemberMLR Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool.........................AEPPool AEP System's Money Pool.
MPSC...............................MichiganMPSC Michigan Public Service Commission.
MTM................................Mark-to-Market.
MW.................................Megawatt.
MWH................................Megawatthour.
NOx................................NitrogenMTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx Nitrogen oxide.
NOx Rule...........................ARule 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................................NuclearNRC Nuclear Regulatory Commission.
OCC................................TheOCC The Corporation Commission of the State of Oklahoma.
Ohio Act...........................TheAct The Ohio Electric Restructuring Act of 1999.
Ohio EPA...........................OhioEPA Ohio Environmental Protection Agency.
OPCo..............................OPCo Ohio Power Company, an AEP electric utility subsidiary.
PJM................................PennsylvaniaPJM Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO................................PublicPSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO...............................ThePTB Price-to-Beat.
PUCO The Public Utilities Commission of Ohio.
PUCT...............................ThePUCT The Public Utility Commission of Texas.
PUHCA..............................PublicPUHCA Public Utility Holding Company Act of 1935, as amended.
PURPA..............................ThePURPA The Public Utility Regulatory Policies Act of 1978.
RCRA...............................ResourceRCRA Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............AEPSubsidiaries AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
REP................................RetailREP Retail Electric Provider.
Rockport Plant.....................APlant A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................RegionalRTO Regional Transmission Organization.
SEC................................SecuritiesSEC Securities and Exchange Commission.
SFAS...............................StatementSFAS Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................Statement71 Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation.
---------------------------------------------------------
SFAS 101...........................Statement101 Statement of Financial Accounting Standards No. 101,
Accounting for the Discontinuance of Application of Statement 71.
----------------------------------------------------------------
SFAS 133...........................Statement133 Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities.
------------------------------------------------------------
SFAS 143...........................Statement143 Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations.
SNF................................Spent-------------------------------------------
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................................SouthwestSPP Southwest Power Pool.
STP................................SouthSTP South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC.............................STPSTPNOC STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
SWEPCo.............................SouthwesternSWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEPTCC AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
Power and Light Company (CPL)].subsidiary.
Tenor Maturity of a contract.
Texas Legislation..................LegislationLegislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC................................AEPTNC AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
Utilities Company (WTU)].subsidiary.
TVA ...............................TennesseeTennessee Valley Authority.
U.K................................TheU.K. The United Kingdom.
VaR................................ValueVaR Value at Risk, a method to quantify risk exposure.
Virginia SCC.......................VirginiaSCC Virginia State Corporation Commission.
WVPSC..............................PublicWVPSC Public Service Commission of West Virginia.
WPCo...............................WheelingWPCo Wheeling Power Company, an AEP electric distribution subsidiary.
Zimmer Plant.......................WilliamPlant William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
iv
FORWARD LOOKINGFORWARD-LOOKING INFORMATION
These reports made by AEP and its registrant subsidiaries contain
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and its registrant
subsidiaries believe that their expectations are based on reasonable
assumptions, any such statements may be influenced by factors that could
cause actual outcomes and results to be materially different from those
projected. Among the factors that could cause actual results to differ
materially from those in the forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our service
territories.
o The ability to recover stranded costs in connection with possible/proposed deregulation.
o New legislation and government regulation.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 acquiring new business ventures and disposing of existing investments that no longer match
our corporate profile.
o International and country-specific developments affecting foreign
investments including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in our service territory and changes
in market
demand and demographic patterns.
o Inflationary trends.
o 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
OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002----------------------------------------------
Results of Operations
American Electric Power Company, Inc.'s principal operating business segments
and their major activities are:
Utility Operations
oDomestic generation of electricity for sale to retail
and wholesale customers
oDomestic electricity transmission and distribution
Investments - Gas Operations
oGas pipeline and storage services
Investments - UK Operations
oInternational generation of electricity for sale to wholesale customers
Investments - Other
oCoal mining, bulk commodity barging operations and other
energy supply businesses
o
Results of OperationsCompany's consolidated Net Income of $440 million or $1.24 per share in(Loss) by operating
segment for the firstthird 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 included $193 million ofis discussed below according to the
operating segments listed above. Income from Cumulative Effect of Accounting Changes
(see Note 3).Continuing Operations (or Income
Before Discontinued Operations and Cumulative Effect increased $97of 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 61% due$0.65 per share compared to improved earnings$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 system sales
resultingContinuing 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 interactionsCumulative Effect of plant availability, the colder winter weather
and higher margins.Accounting Changes in Revenues
AEP's total revenue increased 36%
in the first quarter resulting from the implementation of 2003. The following
table showsSFAS 143 (see Note 3),
partially offset by $49 million (net of tax) of Loss from the componentsCumulative Effect
of revenue.
Increase (Decrease)
(in millions) %
REVENUES:
Electric Generation $ 441 31
Electric TransmissionAccounting 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 Distribution 74 9
Gas Pipeline and Storage 669 155
Investments ( 96) (32)
TOTAL REVENUES $ 1,088 36
The increasea $350 million (net of tax) charge for the implementation of SFAS 142
(see Note 3). A common stock issuance in revenues wasMarch 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 levelscosts of Electric
Generationreplacement power. Our Texas supply represents the
gross margin for output of generating units in the ERCOT region and
Electric Transmissionfrom "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 Distributiona continued weak economy.
o Reduced demand in our Ohio Companies resulting from plant
availabilitymild 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
colder winter weather as well asearlier estimate of market price derived by a PUCT model. We filed a
plan of divestiture with the higher revenue from
Gas Pipeline and StoragePUCT 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, resulting primarily from higher prices. Heating
degree days were up 20% which resultedincreased $76 million in higher residential KWH sales of 4%.
System sales volume increased 10% to 7,681 gigawatt hours. Higher gas prices
were caused by the
decreasing availability of gas. Fuel inventories at gas
storage facilities were reducedcurrent quarter due to low levels reflecting the colder winter
weather compared to 2002. Investment revenues decreased 32% due to the completed
constructioncost generation that was available because
of a gas-fired plant for a third partyweather-related reductions in the summer of 2002retail demand, favorable power
optimization and a
reductionhigher peak prices in U.K. operating margins due to market conditions.
ChangesECAR.
o A $13 million decrease in Expenses
Increase (Decrease)
(in millions) %
EXPENSES:
Fuel for Electric Generation $ 39 6
Purchased Electricity for Resale 176 N.M.
Purchased Gas for Resale 795 225
Maintenance and Other Operation (43) (4)
Depreciation and Amortization (17) (5) Taxes Other Than Income Taxes (3) (2)
TOTAL OPERATING EXPENSES $947 37
N.M. = Not Meaningful
Theprimarily
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 Fuel for Electric Generation includes the effect ofoperating income partially offset by an increase in
AEP's domestic netnonoperating 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 6%weather-related reductions in
retail demand, favorable power optimization, higher peak prices and
increased sales in ECAR. In addition, we experienced higher generation outputthird-party
transmission volumes and recognized a loss on the settlement of 31%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
U.K. operation. The increase in Purchased Electricity for Resale expense was
primarily attributable to an increase in MWH purchased to meet the demand.
Purchased Gas for Resale increased due primarily to higher market prices.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 effectsale of materialthe Texas REPs.
o Depreciation and labor costs relatedAmortization, which decreased by $28 million due to
the constructionchange 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 gas-firedcontinued 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 apotential 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 party thatquarter of 2002, which did not
recur during 2003. The increased loss was completedpartially 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. Project feesWe 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 constructioncurrent 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 gas-fired plantNordic 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 a third party were recognizedinvestments in revenues on a percentage of
completion method, consequently,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 decreasecomparable 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 for material and labor
cost does not affect net income. In addition, payroll expense decreased due in
partlower costs to
personnel reductions in late 2002.wind-down operations. These decreases were partially offset by increasesour 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 U.K.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 expenses, pensioncash on hand make up the $1,708 million Cash and postretirement benefits
expense, accretion expense relatedCash
Equivalents balance on our Consolidated Balance Sheet at September 30, 2003.
We maintain the $300 million cash liquidity reserve fund to asset retirement obligations (ARO) SFAS
143support 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
26).
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 explanation$1,964 million
of decrease in Depreciationlong-term) and Amortization
expense below)increased available cash primarily through the issuance of
long-term financing ($4,146 million), the issuance of common stock ($1,177
million) and nuclear refueling outage amortization expenses.
The decrease in Depreciation and Amortization expense is primarily due to the
adoption of SFAS 143 for certain subsidiary utility companies effective January
1, 2003. Effective January 1, 2003 the generation depreciation rateof cash from operating activities. Also, see Note 12
for certainfurther 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 jurisdictions was reducedassets 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 exclude the non-ARO removal cost
portion that was includedcalculate our stranded costs in Texas (see Note 5). We expect to
receive final bids in the depreciation rate. In addition, certain
amortization relatedfourth quarter of 2003.
During the second quarter of 2003, we also hired an advisor to nuclear decommissioning costs was reclassified as ARO
accretion expenseevaluate our coal
business, which is includedhas resulted in Maintenancereceipt 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 Other Operations expense.
Additionally, APCo reduced its Depreciation and Amortization expense related to
the amortization of generation related regulatory assets due to the return to
SFAS 71 regulatory accountingrequest for the West Virginia jurisdiction (see Note 6 for
further discussion of the return to SFAS 71 regulatory accounting).
Other Income and Other Expenses
Other Income includes non-operating revenue including non-utility revenue
associated with energy related projects for customers, equity earnings of
non-consolidated subsidiaries, a gainproposal on the sale
of our customer careLouisiana Intrastate Gas and Jefferson Island Storage Facility operations
in Texas, and interest and miscellaneous income.
Other Expenses includes non-utility expenses associated with energythe 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 projects for customers, losses on dispositions of property, donations and
various other non-operating and miscellaneous expenses.
Other Income increased mainly due to a gain of $39 million on the
possible sale of our customer care operationsinterest in Texas and an increase in miscellaneous income. Inthese IPPs.
During the firstfourth 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 sold Mutual Energy Service Company, a customer
care operation which was createdEast companies with final agreements to servebe
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
deregulated
Texas market,other states remain pending.
In February 2003, Virginia enacted legislation that prohibited the transfer of
transmission assets in its jurisdiction to Alliance Data Systems. This sale continuesan RTO until, at the earliest, July
2004 and only with the approval of Virginia SCC.
In April 2003, FERC approved our exittransfer 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 businessof 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 refocusesrelated
revenues through September 30, 2003 based upon our resources on
wholesale generation and power supply markets. Miscellaneous income increased
due to additional contractsestimate.
In July 2003, the PUCT Staff published their proposed filing package for the
staffing2004 true-up proceeding. Within the filing package are instructions and sample
schedules that demonstrate the calculation of nonassociated companies'
outages. Other Expenses increased duethe 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 increased non-utility expenses
associatedthe 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 energy related construction projectsthe
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 third parties.
Other Changes
The increasefurther 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 Income Taxes istwo 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 increase in pre-tax income and the tax
effectsinflux of
foreign operations.
The increase in Interest was primarily due to an increase in outstanding
balances of long-term debtfish in the first quarterplant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of 2003. The increase was
partially offsetdamage 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 decrease in short-term debt interest expense due to a
decrease in outstanding balancesscheduled refueling outage.
Litigation
Federal EPA Complaint and Notice of short-term debtViolation
As discussed in the first quarter2002 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 2003.
Cumulative Effectstates alleged APCo, CSPCo, I&M, OPCo and eleven
unaffiliated utilities made modifications to generating units at coal-fired
generating plants in violation of Accounting Changesthe Clean Air Act. The Cumulative EffectFederal EPA filed
complaints against our subsidiaries in U.S. District Court for the Southern
District of Accounting ChangesOhio. 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 one-time after-taxnumber
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 adoptingnew 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 143133 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 implementingroll 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 EITF 02-3 (see
Notes 2operations, cash flows or financial condition. The following
table shows the end, high, average, and 3).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)(Unaudited)
Three Months Ended March 31,Nine Months Ended
2003 2002 REVENUES:
2003 2002
---- ---- ---- ----
REVENUES
- ----------------------------------------------------------------------
Electric Generation $1,863 $ 1,422
Electric Transmission
Utility Operations $3,111 $2,940 $8,512 $7,858
Gas Operations 860 700 2,791 1,803
U.K. Operations and Distribution 910 836
Gas Pipeline and Storage 1,102 433
Investments 205 301Other 138 171 555 723
------- ------- ------- -------
TOTAL REVENUES 4,080 2,992
EXPENSES:4,109 3,811 11,858 10,384
------- ------- ------- -------
EXPENSES
- ----------------------------------------------------------------------
Fuel for Electric Generation 660 621916 666 2,426 1,918
Purchased Electricity for Resale 205 29206 306 626 413
Purchased Gas for Resale 1,149 354828 625 2,685 1,691
Maintenance and Other Operation 963 1,006977 868 2,921 3,073
Depreciation and Amortization 315 332334 362 985 1,045
Taxes Other Than Income Taxes 188 191179 202 524 576
------- ------- ------- -------
TOTAL EXPENSES 3,480 2,5333,440 3,029 10,167 8,716
------- ------- ------- -------
OPERATING INCOME 600 459669 782 1,691 1,668
------- ------- ------- -------
Other Income 75 115 279 176
------- ------- ------- -------
INTEREST AND OTHER INCOME 118 12
OTHER EXPENSES 45 20
LESS: INTEREST 205 195
PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIESCHARGES
- ----------------------------------------------------------------------
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 2
MINORITY INTEREST IN FINANCE SUBSIDIARY7 8
Minority Interest in Finance Subsidiary - 9 917 27
------- ------- ------- -------
TOTAL 339 268 867 708
------- ------- ------- -------
INCOME BEFORE INCOME TAXES 456 245
INCOME TAXES 200 86405 629 1,103 1,136
Income Taxes 148 243 408 433
------- ------- ------- -------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT 256 159
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (9) 22257 386 695 703
Discontinued Operations (net of tax) - 39 (16) (35)
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX):(Net of Tax)
- ----------------------------------------------------------------------
Goodwill and Other Intangible Assets - - - (350)
Accounting for Risk Management Contracts - - (49) -
Asset Retirement Obligation - - 242 -
------- ------- ------- -------
NET INCOME (LOSS) $ 440 $ (169)$257 $425 $872 $318
======= ======= ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 356 322395 339 382 329
======= ======= ======= =======
EARNINGS (LOSS) PER SHARE:SHARE
- ----------------------------------------------------------------------
Income Before Discontinued Operations andAnd Cumulative Effect
of Accounting Changes $ 0.72 $ 0.49$0.65 $1.14 $1.81 $2.14
Discontinued Operations (0.02) 0.07- 0.11 (0.04) (0.10)
Cumulative Effect of Accounting Changes 0.54 (1.08)
Earnings (Loss) Per Share (Basic and Diluted) $ 1.24 $(0.52)- - 0.51 (1.07)
------- ------- ------- -------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE) $0.65 $1.25 $2.28 $0.97
======= ======= ======= =======
CASH DIVIDENDS PAID PER SHARE $ 0.60 $ 0.60
See Notes to Consolidated Financial Statements beginning on page L-1.$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
(UNAUDITED)
March 31,ASSETS
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in millions)
CURRENT ASSETS
CURRENT ASSETS:
- ----------------------------------------------------------------------------------
Cash and Cash Equivalents $ 1,764 $ 1,213$1,708 $1,213
Accounts Receivable (net) 2,5721,535 1,740
Fuel, Materials and Supplies 9661,197 1,166
Risk Management Assets 1,1051,014 1,012
Other 1,037901 935
-------- --------
TOTAL CURRENT ASSETS 7,4446,355 6,066
-------- --------
PROPERTY, PLANT AND EQUIPMENT:EQUIPMENT
- ----------------------------------------------------------------------------------
Electric:
Production 17,23918,616 17,031
Transmission 5,9096,099 5,882
Distribution 9,5859,815 9,573
Other (including gas, coal mining and nuclear fuel) 3,9113,997 3,965
Construction Work in Progress 1,510973 1,406
Total Property, Plant and Equipment 38,154-------- --------
TOTAL 39,500 37,857
Less: Accumulated Depreciation and Amortization 15,82616,488 16,173
NET PROPERTY, PLANT AND EQUIPMENT 22,328-------- --------
TOTAL-NET 23,012 21,684
REGULATORY-------- --------
OTHER NON-CURRENT ASSETS
2,669- ----------------------------------------------------------------------------------
Regulatory Assets 2,612 2,688
SECURITIZED TRANSITION ASSETS 726Securitized Transition Assets 703 735
INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 291Investments in Power and Distribution Projects 221 283
GOODWILLGoodwill 397 396
396
ASSETS HELD FOR SALE 280 292
LONG-TERM RISK MANAGEMENT ASSETS 812Assets Held for Sale 194 277
Assets of Discontinued Operations - 15
Long-term Risk Management Assets 818 819
OTHER ASSETS 1,955Other 1,767 1,783
-------- --------
TOTAL 6,712 6,996
-------- --------
TOTAL ASSETS $36,901$36,079 $34,746
See Notes to Consolidated Financial Statements beginning on page L-1.======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2003 and December 31, 2002
(Unaudited)
2003 2002
---- ----
(in millions)
CURRENT LIABILITIES:
LIABILITIES
- ---------------------------------------------------------------------------------------
Accounts Payable $ 2,930 $ 2,030$1,700 $2,030
Short-term Debt 239443 3,164
Long-term Debt Due Within One Year 1,6961,234 1,633
Risk Management Liabilities 1,2681,029 1,113
Other 2,0201,782 1,802
-------- --------
TOTAL CURRENT6,188 9,742
-------- --------
NON-CURRENT LIABILITIES
8,153 9,742
LONG-TERM DEBT 10,436- ---------------------------------------------------------------------------------------
Long-term Debt 12,323 8,487
EQUITY UNIT SENIOR NOTESEquity Unit Senior Notes 376 376
LONG-TERM RISK MANAGEMENTLong-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 543 481
DEFERRED INCOME TAXES 4,037 3,916
DEFERRED INVESTMENT TAX CREDITS 448 455
DEFERRED CREDITS AND REGULATORY LIABILITIES 830 770
DEFERRED GAIN ON SALE AND LEASEBACK27,560 26,457
-------- --------
Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption 61 -
ROCKPORT PLANT UNIT 2 183 185
LIABILITIES HELD FOR SALE 161 142
OTHER NONCURRENT LIABILITIES 2,073 1,903
COMMITMENTS AND CONTINGENCIES (Note 7)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIESCertain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries - 321
321
MINORITY INTEREST IN FINANCE SUBSIDIARYMinority Interest in Finance Subsidiary - 759
759
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 144Cumulative Preferred Stocks of Subsidiaries - 145
COMMON SHAREHOLDERS' EQUITY
- ---------------------------------------------------------------------------------------
Common Stock-Par Value $6.50:
2003 2002
---- ----
Shares Authorized..Authorized. . 600,000,000. . . . . . . . .600,000,000 600,000,000
Shares Issued. . . . .403,993,412. . . . . . . . .404,004,712 347,835,212
(8,999,992 shares were held in treasury at March 31,September 30, 2003 and December 31, 2002) 2,626 2,261
Paid-in Capital 4,1754,184 3,413
Accumulated Other Comprehensive Income (Loss) (602)(745) (609)
Retained Earnings 2,2382,393 1,999
-------- --------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,4378,458 7,064
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS'EQUITY
$36,901SHAREHOLDERS' EQUITY $36,079 $34,746
See Notes to Consolidated Financial Statements beginning on page L-1.======== ========
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeFor the Nine Months Ended March 31,September 30, 2003 and 2002
(Unaudited)
2003 2002
---- ----
(in millions)
OPERATING ACTIVITIES:
ACTIVITIES
- -------------------------------------------------------------------------------------
Net Income (Loss) $ 440 $(169)$872 $318
Plus: Discontinued Operations 9 (22)
Net16 35
------- -------
Income from Continuing Operations 449 (191)888 353
Adjustments for Noncash Items:
Depreciation and Amortization 315 336984 1,066
Deferred Income Taxes 27 (59)256 (81)
Deferred Investment Tax Credits (7) (9)(24) (21)
Cumulative Effect of Accounting Changes (193) 350
(Gain)/Loss on SaleImpairments 46 -
Amortization of Assets (36) -Deferred Property Taxes 88 73
Amortization of Cook Plant Restart Costs 30 30
Mark to Market of Risk Management Contracts 69 158(83) 217
Changes in Certain Current Assets and Liabilities:
Accounts Receivable, (net) (834) (796)net 176 (868)
Fuel, Materials and Supplies 165 101(59) (176)
Accrued Utility Revenues (48) (51)70 (255)
Prepayments and Other (74) (49)(37) (387)
Accounts Payable 905 43(400) 771
Taxes Accrued 196 12(34) 126
Interest Accrued 29 94
Rent Accrued - Rockport Plant Unit 2 37 3730 107
Over/Under Fuel Recovery 74 (31)131 (57)
Change in Other Assets (209) (341)(224) (373)
Change in Other Liabilities (90) 376(92) (129)
------- -------
Net Cash Flows From (Used For) Operating Activities 775 (20)1,553 746
------- -------
INVESTING ACTIVITIES:ACTIVITIES
- -------------------------------------------------------------------------------------
Construction Expenditures (324) (300)(941) (1,137)
Proceeds from Sale of Assets 35 -49 1,116
Other - (32)7 2
------- -------
Net Cash Flows Used For Investing Activities (289) (332)(885) (19)
------- -------
FINANCING ACTIVITIES:ACTIVITIES
- -------------------------------------------------------------------------------------
Issuance of Common Stock 1,177 14656
Issuance of Long-term Debt 2,525 8724,146 1,819
Issuance of Equity Unit Senior Notes - 334
Change in Short-term Debt, (net) (2,925) (49)net (2,825) (806)
Retirement of Long-term Debt (509) (295)(1,964) (1,800)
Retirement of Preferred Stock (2) (10)
Retirement of Minority Interest (225) -
Dividends Paid on Common Stock (203) (193)(480) (590)
------- -------
Net Cash Flows FromUsed For Financing Activities 65 349(173) (397)
------- -------
Effect of Exchange Rate Change on Cash - (14)(3)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 551 (17)495 327
Cash and Cash Equivalents at Beginning of Period 1,213 224
------- -------
Cash and Cash Equivalents at End of Period $1,764 $ 207$1,708 $551
======= =======
Net Decrease in Cash and Cash Equivalents from Discontinued Operations $ (3) $ (9)$(1) $(25)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 8 108
------- -------
Cash and Cash Equivalents from Discontinued Operations - End of Period $ 5 $ 99
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $177 million and $126
million in 2003 and 2002, respectively. There was no cash paid for income taxes
in 2003. Cash paid for income taxes in 2002 was $94 million.
See Notes to Consolidated Financial Statements beginning on page L-1.$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)
(UNAUDITED)
(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 3 3108 568 676
Common Stock Dividends (193) (193)(590) (590)
Other 6 4 10
8,049
Comprehensive Income (Loss):(80) 15 (65)
-------
TOTAL 8,250
-------
COMPREHENSIVE INCOME (LOSS)
- -----------------------------------------------------------
Other Comprehensive Income (Loss), Net of TaxesTaxes:
Foreign Currency Translation Adjustments (6) (6)97 97
Unrealized LossesGains on Cash Flow Hedges (38) (38)
Net Loss (169) (169)
Total Comprehensive Income (Loss) (213)
MARCH 31,4 4
Unrealized Losses on Securities Available for Sale (3) (3)
NET INCOME 318 318
-------
TOTAL COMPREHENSIVE INCOME 416
------- ------- ------- ------ -------
SEPTEMBER 30, 2002 $2,156 $2,912 $2,938 $(170) $7,836$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 (203) (203)(480) (480)
Common Stock Expense (35) (35)(36) (36)
Other (15)(5) 2 (13)
7,990
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes
Foreign Currency Translation Adjustments
13 13
Unrealized Gains on Securities 1 1
Unrealized Losses on Cash Flow Hedges
(22) (22)
Minimum Pension Liability 15 15
Net Income 440 440
Total Comprehensive Income 447
MARCH 31, 2003 $2,626 $4,175 $2,238 $(602) $8,437
See Notes to Consolidated Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
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 recovery of costs including a FERC approved rate of return on common
equity and a return on other capital net of temporary cash investments.
Results of Operations
Net Income declined $97 thousand or 5% for the first quarter of 2003 as a result
of terms in the unit power agreements which limits recovery of return on capital
related to operating and in-service ratios of the Rockport Plant calculated and
adjusted monthly.
Changes in Operating Revenues
An increase in Operating Revenues of $10.6 million resulted from an increase in
recoverable expenses, primarily fuel, as generation increased 50% due to an
increase in the Rockport Plant's availability during 2003. Outages for planned
maintenance at both units decreased the Rockport Plant's generation in 2002.
Changes in Operating Expenses Operating expenses increased 22% as follows:
Increase (Decrease)
(in thousands) %
Fuel for Electric Generation $12,897 74
Rent - Rockport Plant
Unit 2 - -
Other Operation (673) (21)
Maintenance (1,325) (45)
Depreciation (12) -
Taxes Other Than Income
Taxes (262) (25)
Income Taxes (156) (24)
Total Operating Expenses $10,469 22
Fuel for Electric Generation expense increased due to a 50% increase in
generation in 2003. Planned maintenance outages during the first quarter of 2002
reduced the Rockport Plant's availability and generation in 2002.
The decreases in Other Operation and Maintenance expenses are primarily due to
higher costs incurred during the 2002 plant outages.
The decrease in Taxes Other Than Income Taxes reflects a decline in the accrual
of real and personal property tax for Indiana for the Rockport Plant, reflecting
a favorable change in the law effective March 2002.
Income Taxes attributable to operations decreased primarily due to a decrease in
pre-tax operating income and a decrease in accrued state income.
Other Changes
The increase in Nonoperating Expense reflects additional expenses related to a
construction project.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES $60,428 $49,875
OPERATING EXPENSES:
Fuel for Electric Generation 30,397 17,500
Rent - Rockport Plant Unit 2 17,071 17,071
Other Operation 2,549 3,222
Maintenance 1,651 2,976
Depreciation 5,621 5,633
Taxes Other Than Income Taxes 791 1,053
Income Taxes 497 653(3)
-------
TOTAL OPERATING EXPENSES 58,577 48,108
OPERATING INCOME 1,851 1,767
NONOPERATING INCOME 2 2
NONOPERATING EXPENSES 217 12
NONOPERATING INCOME TAX CREDITS 894 832
INTEREST CHARGES 734 696
NET INCOME $ 1,796 $ 1,893
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
BALANCE AT BEGINNING OF PERIOD $18,163 $13,761
NET INCOME 1,796 1,893
CASH DIVIDENDS DECLARED 1,171 1,050
BALANCE AT END OF PERIOD $18,788 $14,604
The common stock of AEGCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $638,481 $637,095
General 4,643 4,728
Construction Work in Progress 10,707 10,390
Total Electric Utility Plant 653,831 652,213
Accumulated Depreciation 364,316 358,174
NET ELECTRIC UTILITY PLANT 289,515 294,039
OTHER PROPERTY AND INVESTMENTS 119 119
CURRENT ASSETS:
Accounts Receivable - Affiliated Companies 21,583 18,454
Fuel 18,005 20,260
Materials and Supplies 4,859 4,913
Prepayments 73 -
TOTAL CURRENT ASSETS 44,520 43,627
REGULATORY ASSETS 5,701 4,970
DEFERRED CHARGES 9,297 6,974
TOTAL ASSETS $349,152 $349,729
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 18,788 18,163
Total Common Shareholder's Equity 43,222 42,597
Long-term Debt 44,804 44,802
TOTAL CAPITALIZATION 88,026 87,399
OTHER NONCURRENT LIABILITIES 1,333 301
CURRENT LIABILITIES:
Advances from Affiliates 9,650 28,034
Accounts Payable:
General - 26
Affiliated Companies 12,585 15,907
Taxes Accrued 7,294 2,327
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 633 1,111
TOTAL CURRENT LIABILITIES 53,589 52,368
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 109,654 111,046
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 52,108 52,943
Amounts Due to Customers for Income Taxes 16,143 16,670
TOTAL REGULATORY LIABILITIES 68,251 69,613
DEFERRED INCOME TAXES 28,299 29,002
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $349,152 $349,729
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 1,796 $ 1,893
Adjustment for Noncash Items:
Depreciation 5,621 5,633
Deferred Income Taxes (1,230) (1,470)
Deferred Investment Tax Credits (835) (835)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (1,392) (1,392)
Deferred Property Taxes (2,329) (2,693)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (3,129) 1,337
Fuel, Materials and Supplies 2,309 (1,214)
Accounts Payable (3,348) (1,221)
Taxes Accrued 4,967 5,529
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets (1,021) 586
Change in Other Liabilities 554 (545)
Net Cash Flow From Operating Activities 20,427 24,072
INVESTING ACTIVITIES - Construction Expenditures (872) (4,282)
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (18,384) (15,511)
Dividends Paid (1,171) (1,050)
Net Cash Flows Used For Financing Activities (19,555) (16,561)
Net Increase in Cash and Cash Equivalents - 3,229
Cash and Cash Equivalents at Beginning of Period - 983
Cash and Cash Equivalents at End of Period $ - $ 4,212
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $1,123,000 and
$1,108,000 and for income taxes was $(384,000) and $176,000 in 2003 and 2002,
respectively.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
AEP Texas Central Company (TCC), formerly known as Central Power and Light
Company (CPL), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in southern Texas. TCC sells
electric power to utilities, municipalities, rural electric cooperatives and
beginning in 2002 to retail electric providers (REPs) in Texas.
Wholesale risk management activities are conducted on TCC's behalf by AEPSC.
TCC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.
On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.
Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TCC submitted a plan for separation that was subsequently approved by the
PUCT. TCC functionally separated its generation from its transmission and
distribution operations and AEP formed separate affiliated REPs, Mutual Energy
CPL and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual
Energy CPL provides default electric service to residential and small commercial
customers (customers eligible for price-to-beat rates). AEP Texas Commercial &
Industrial Retail Limited Partnership provides default electric service to large
commercial and industrial customers not eligible for price- to-beat rates.
Mutual Energy CPL, a separate legal entity that was an AEP subsidiary (not owned
by or consolidated with TCC), was sold in December 2002.
Since REPs are the electricity suppliers to retail customers in the ERCOT area,
TCC sells its generation to the REPs and other market participants and provides
transmission and distribution services to retail customers of the REPs in the
TCC service territory. As a result of the provision of retail electric service
by REPs, effective January 1, 2002, TCC no longer supplies electricity directly
to retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in TCC's sales as further described below under
"Results of Operations."
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 with Mutual Energy CPL
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.
Results of Operations
In 2003 Net Income increased $40 million or 164% driven by a $56 million ($36
million, net of tax) increase in revenues associated with recognition of
stranded costs in Texas, and a $5.0 million ($3.2 million, net of tax) increase
in profits on derivative contracts.
Changes in Operating Revenues
Increase (Decrease)
(in millions) %
Electric Generation $166.4 198
Electric Transmission and Distribution
124.9 346
Sales to AEP Affiliates (141.9) (89)
Total Operating Revenues $149.4 54
In 2003, Electric Generation revenues increased due to the reclassification of
energy revenues as a result of the sale of Mutual Energy CPL in December 2002,
discussed above, and increased MWH sales at higher prices, and increased
revenues from ERCOT of $77 million. These revenues were offset in part by a
decrease in average electric rates, as 2002 included a transition period which
included fuel revenue collections from retail customers; and a reduction of $27
million resulting from a provision for rate refund (see Note 5).
Additionally, delivery charges provided to Mutual Energy CPL are classified as
Sales to AEP Affiliates in 2002, whereas in 2003 they are classified as
Electricity Transmission and Distribution revenue. Actual delivered MWHs
increased in 2003. Revenues for 2003 include $56 million of revenue associated
with recognition of stranded costs in Texas (see Note 6). Electric Transmission
and Distribution revenue also included revenues received for securitized assets
beginning in February 2002 and revenues from ERCOT for system management
services.
In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification
of revenues as a result of the sale of Mutual Energy CPL in December 2002,
discussed above.
Changes in Operating Expenses
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $ 0.3 1
Fuel from Affiliates for Electric Generation
11.0 40
Purchased Electricity for Resale 68.1 N.M.
Purchased Electricity from AEP Affiliates
3.6 46
Other Operation 3.4 5
Maintenance 5.2 47
Depreciation and Amortization 2.2 5
Taxes Other Than Income Taxes (4.9) (18)
Income Taxes 24.0 229
Total Operating Expenses $112.9 51
N.M. = Not meaningful
The increase in total fuel expense was due to an increase in the average unit
cost of fuel offset in part by decreased MWH generation. The increase in the
average unit cost was due to gas generation as the per unit cost of gas more
than doubled from 2002 to 2003, while the actual gas MWH generation decreased
due to the mothballing of several gas plants in late 2002. Nuclear generation
decreased due to outages at the STP nuclear plant during the first quarter of
2003. See Note 7 for further information regarding the outage at the STP nuclear
plant.
The increase in total purchased electricity expense in 2003 was mainly due to
increased MWHs purchased as a result of the mothballed plants, the STP outage
and higher open market purchase prices.
Other Operation expense increased due primarily to the accretion expense for
nuclear decommissioning associated with the adoption of SFAS 143 (see Note 2). A
corresponding offsetting decrease in Depreciation and Amortization is also a
result of the adoption of SFAS 143. See Depreciation and Amortization
explanation below.
Maintenance expense increased due to an unscheduled outage at one of the nuclear
units and a refueling outage at the other nuclear unit (see Note 7).
The increase in Depreciation and Amortization is attributable to the absence in
2003 of an excess earnings favorable true-up adjustment offset in part by
reduced expense attributable to the adoption of SFAS 143, the amortization of
regulatory assets associated with the securitization during the first quarter of
2002 and decreased depreciation due to several plants mothballed during late
2002.
The decrease in Taxes Other Than Income Taxes resulted primarily from decreased
gross receipts tax, due to deregulation.
The increase in Income Taxes is due to an increase in pre-tax income.
Other Changes
Nonoperating Income increased as a result of premium payments on derivative
contracts, offset in part by decreased non-utility revenue associated with
energy related construction projects for third parties. Nonoperating Expenses
also decreased due to lower expenses associated with energy related construction
projects for third parties.
Cumulative Effect of Accounting Change
This amount represents the one-time after-tax effect of the application of EITF
02-3 (see Notes 2 and 3).
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $250,377 $ 83,988
Electric Transmission and Distribution 161,006 36,060
Sales to AEP Affiliates 16,975 158,862
TOTAL OPERATING REVENUES 428,358 278,910
OPERATING EXPENSES:
Fuel for Electric Generation 27,339 26,989
Fuel from Affiliates for Electric Generation 38,289 27,339
Purchased Electricity for Resale 72,122 4,012
Purchased Electricity from AEP Affiliates 11,562 7,927
Other Operation 69,402 65,986
Maintenance 16,099 10,959
Depreciation and Amortization 44,073 41,847
Taxes Other Than Income Taxes 22,979 27,922
Income Taxes 34,483 10,484
TOTAL OPERATING EXPENSES 336,348 223,465
OPERATING INCOME 92,010 55,445
NONOPERATING INCOME 10,162 9,531
NONOPERATING EXPENSES 5,195 9,387
NONOPERATING INCOME TAX EXPENSE 558 133
INTEREST CHARGES 31,982 31,011
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 64,437 24,445
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX)
122 -
NET INCOME 64,559 24,445
PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60
EARNINGS APPLICABLE TO COMMON STOCK $ 64,499 $ 24,385
The common stock of TCC is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND7,722
-------
COMPREHENSIVE INCOME (UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
(in thousands)
JANUARY 1, 2002 $168,888 $405,015 $826,197 $(LOSS)
- $1,400,100
Redemption of Common Stock (113,596) (272,409) (386,005)
Common Stock Dividends (38,502) (38,502)
Preferred Stock Dividends (60) (60)
975,533
Comprehensive Income:
Other Comprehensive Income - -
Net Income 24,445 24,445
Total Comprehensive Income 24,445
MARCH 31, 2002 $ 55,292 $132,606 $812,080 $ - $ 999,978
JANUARY 1, 2003 $ 55,292 $132,606 $986,396 $(73,160) $1,101,134
Common Stock Dividends (30,201) (30,201)
Preferred Stock Dividends (60) (60)
1,070,873
Comprehensive Income:-----------------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
Foreign Currency Translation Adjustments 25 25
Unrealized LossLosses on Cash Flow Power Hedges (1,018) (1,018)
Net Income 64,559 64,559
Total Comprehensive Income 63,541
MARCH 31, 2003 $ 55,292 $132,606 $1,020,694 $(74,178) $1,134,414
See Notes to Financial Statements beginning(177) (177)
Unrealized Gains on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, December 31,
2003 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,977,890 $2,903,942
Transmission 715,195 698,964
Distribution 1,305,884 1,296,731
General 260,834 258,386
Construction Work in Progress 180,178 200,947
Nuclear Fuel 270,521 266,766
Total Electric Utility Plant 5,710,502 5,625,736
Accumulated Depreciation and Amortization 2,356,530 2,405,492
NET ELECTRIC UTILITY PLANT 3,353,972 3,220,244
OTHER PROPERTY AND INVESTMENTS 4,219 3,977
SECURITIZED TRANSITION ASSETS 725,597 734,591
LONG-TERM RISK MANAGEMENT ASSETS 11,547 4,392
CURRENT ASSETS:
Cash and Cash Equivalents 32,796 85,420
Advances to Affiliates 18,346 -
Accounts Receivable:
General 190,905 113,543
Affiliated Companies 110,291 121,324
AllowanceSecurities Available for Uncollectible Accounts (230) (346)
Fuel Inventory 22,103 32,563
Materials and Supplies 47,220 51,593
Accrued Utility Revenues 27,540 27,150
Risk Management Assets 21,395 22,493
Prepayments and Other Current Assets 4,769 2,133
TOTAL CURRENT ASSETS 475,135 455,873
REGULATORY ASSETS 570,058 458,552
REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION
321,156 336,444
NUCLEAR DECOMMISSIONING TRUST FUND 97,128 98,474
DEFERRED CHARGES 88,896 43,891
TOTAL ASSETS $5,647,708 $5,356,438
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, December 31,
2003 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
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) (74,178) (73,160)
Retained Earnings 1,020,694 986,396
Total Common Shareholder's Equity 1,134,414 1,101,134
Preferred Stock 5,942 5,942
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of TCC 136,250 136,250
Long-term Debt 1,980,640 1,209,434
TOTAL CAPITALIZATION 3,257,246 2,452,760
OTHER NONCURRENT LIABILITIES 309,028 74,572
CURRENT LIABILITIES:
Short-term Debt - Affiliates - 650,000
Long-term Debt Due Within One Year 209,705 229,131
Advances from Affiliates (net) - 126,711
Accounts Payable - General 81,997 72,199
Accounts Payable - Affiliated Companies 65,725 36,242
Customer Deposits 1,803 666
Taxes Accrued 94,315 24,791
Interest Accrued 24,920 51,205
Risk Management Liabilities 28,334 19,811
Other 18,142 36,698
TOTAL CURRENT LIABILITIES 524,941 1,247,454
DEFERRED INCOME TAXES 1,239,961 1,261,252
DEFERRED INVESTMENT TAX CREDITS 116,384 117,686
LONG-TERM RISK MANAGEMENT LIABILITIES 5,824 1,713
REGULATORY LIABILITIES AND DEFERRED CREDITS 194,324 201,001
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $5,647,708 $5,356,438
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 64,559 $ 24,445
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 44,073 41,847
Deferred Income Taxes (2,260) (8,083)
Deferred Investment Tax Credits (1,302) (1,302)
Cumulative Effect of Accounting Change (122) -
Mark-to-Market of Risk Management Contracts 5,197 6,466
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (66,445) (69,400)
Fuel, Materials and Supplies 14,833 (1,359)
Interest Accrued (26,285) 8,942
Accrued Utility Revenue (390) (4,458)
Accounts Payable 39,281 (28,577)
Taxes Accrued 69,524 17,767
Deferred Property Tax (31,590) (32,899)
Change in Other Assets (51,108) (20,966)
Change in Other Liabilities (15,185) (19,726)
Net Cash Flows From (Used For) Operating Activities 42,780 (87,303)
INVESTING ACTIVITIES:
Construction Expenditures (21,851) (21,002)
Other - -
Net Cash Flows Used For Investing Activities (21,851) (21,002)
FINANCING ACTIVITIES:
Change in Short-term Debt Affiliated (Net) (650,000) -
Issuance of Long-term Debt 800,000 796,613
Retirement of Long-term Debt (48,235) (149,998)
Change in Advances to/from Affiliates (Net) (145,057) (115,447)
Retirement of Common Stock - (386,004)
Dividends Paid on Common Stock (30,201) (38,502)
Dividends Paid on Cumulative Preferred Stock (60) (60)
Net Cash Flows From (Used For) Financing Activities (73,553) 106,602
Net Decrease in Cash and Cash Equivalents (52,624) (1,703)
Cash and Cash Equivalents at Beginning of Period 85,420 10,909
Cash and Cash Equivalents at End of Period $ 32,796 $ 9,206
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $55,483,000 and
$18,505,000 and for income taxes was $(22,959,000) and $18,482,000 in 2003 and
2002, respectively.
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
AEP Texas North Company (TNC), formerly known as West Texas Utilities Company
(WTU), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in west and central Texas. TNC
sells electric power to utilities, municipalities, rural electric cooperatives
and beginning in 2002 to retail electric providers (REPs) in Texas.
Wholesale risk management activities are conducted on TNC's behalf by AEPSC.
TNC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.
On JanuarySale 1 1 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in
both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the
majority of its operations being in the ERCOT territory.
Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TNC submitted a plan for separation that was subsequently approved by the
PUCT. TNC functionally separated its generation from its transmission and
distribution operations and AEP formed separate affiliated REPs, Mutual Energy
WTU and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual
Energy WTU provides default electric service to residential and small commercial
customers (customers eligible for price-to-beat rates). AEP Texas Commercial &
Industrial Retail Limited Partnership provides default electric service to large
commercial and industrial customers not eligible for price- to-beat-rates.
Mutual Energy WTU, a separate legal entity that was an AEP subsidiary (not owned
by or consolidated with TNC), was sold in December 2002.
Since REPs are the electricity suppliers to retail customers in the ERCOT area,
TNC sells its generation to the REPs and other market participants and provides
transmission and distribution services to retail customers of the REPs in the
TNC service territory. As a result of the provision of retail electric service
by REPs effective January 1, 2002, TNC no longer supplies electricity directly
to retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in TNC's sales as further described below under
"Results of Operations."
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 with Mutual Energy WTU
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.
Results of Operations
In 2003, Net Income increased $5.8 million or 146% primarily due to the
cumulative effect of accounting changes and increased nonoperating results,
offset by lower Operating Income.
Changes in Operating Revenues
Increase (Decrease)
(in millions) %
Electric Generation $ 41.9 109
Electric Transmission and
Distribution 18.5 126
Sales to AEP Affiliates (47.8) (95)
Total Operating Revenues $ 12.6 12
In 2003, Electric Generation revenues increased due to the reclassification of
energy revenues as a result of the sale of Mutual Energy WTU in December 2002,
discussed above, decreased MWH sales at higher prices and increased revenues
from ERCOT of $17 million. These revenues were offset in part by a decrease in
average electric rates, as 2002 included a transition period which included fuel
revenue collections from retail customers; and a reduction of $13 million
resulting from a provision for rate refund (see Note 5).
The increase in Electric Transmission and Distribution is primarily due to
delivery charges classified as Electric Transmission and Distribution in 2003,
whereas in 2002 they were classified as Sales to AEP Affiliates. In addition,
TNC had increased MWHs delivered in 2003 and increased revenues from ERCOT for
system management services.
In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification
of energy revenues as a result of the sale of Mutual Energy WTU in December
2002, discussed above.
Changes in Operating Expenses
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $ 2.7 32
Fuel from Affiliates for Electric Generation
(10.1) (63)
Purchased Electricity for Resale 18.3 280
Purchased Electricity from AEP Affiliates
7.7 66
Other Operation (3.6) (15)
Maintenance (0.2) (5)
Depreciation and Amortization (2.1) (18)
Taxes Other Than Income Taxes (0.3) (4)
Income Taxes 1.5 50
Total Operating Expenses $ 13.9 15
Net fuel for electric generation decreased due to lower MWHs generated, offset
in part by an increase in the average per unit fuel cost. TNC used coal for 91%
of its generation in 2003 since many of its gas plants were mothballed in late
2002. This higher use of coal helped lower the fuel costs in 2003.
The increase in total Purchased Electricity expense in 2003 was mainly due to
both increased MWHs purchased as a result of the mothballed plants and higher
open market purchase prices.
Other Operation expense decreased in 2003 due to lower uncollectible account
expenses and lower administrative and general expenses.
Depreciation and Amortization expense decreased due to the absence in 2003 of
excess earnings expense adjustments under Texas Restructuring Legislation and
the decrease in depreciation due to the mothballing of several power plants in
late 2002.
The increase in Income Tax Expense is primarily a result of an increase in
pre-tax income.
Other Changes
Nonoperating Income and Nonoperating Expenses increased significantly as a
result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties. Additionally, Nonoperating
Income increased due to increased earnings on derivative contracts.
Interest Charges declined primarily due to lower average borrowings in 2003
versus 2002.
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 Notes 2 and 3).
AEP TEXAS NORTH COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $ 80,369 $ 38,437
Electric Transmission and Distribution 33,124 14,672
Sales to AEP Affiliates 2,769 50,517
TOTAL OPERATING REVENUES 116,262 103,626
OPERATING EXPENSES:
Fuel for Electric Generation 11,461 8,714
Fuel from Affiliates for Electric Generation 6,085 16,266
Purchased Electricity for Resale 24,778 6,513
Purchased Electricity from AEP Affiliates 19,345 11,650
Other Operation 20,619 24,170
Maintenance 4,141 4,356
Depreciation and Amortization 9,532 11,569
Taxes Other Than Income Taxes 6,033 6,300
Income Tax Expense 4,403 2,943
TOTAL OPERATING EXPENSES 106,397 92,481
OPERATING INCOME 9,865 11,145
NONOPERATING INCOME (LOSS) 13,463 (1,488)
NONOPERATING EXPENSES 11,559 1,372
NONOPERATING INCOME TAX EXPENSE (CREDIT) 339 (989)
INTEREST CHARGES 4,665 5,282
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 6,765 3,992
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 3,071 -
NET INCOME 9,836 3,992
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26
EARNINGS APPLICABLE TO COMMON STOCK $ 9,810 $ 3,966
The common stock of TNC is wholly owned by AEP.
See Note to Financial Statements beginning on Page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $137,214 $2,351 $105,970 $ - $245,535
Common Stock Dividends (6,749) (6,749)
Preferred Stock Dividends (26) (26)
238,760
Comprehensive Income:
Other Comprehensive Income - -
Net Income 3,992 3,992
Total Comprehensive Income 3,992
MARCH 31, 2002 $137,214 $2,351 $103,187 $ - $242,752
JANUARY 1, 2003 $137,214 $2,351 $71,942 $(30,763) $180,744
Common Stock Dividends (4,970) (4,970)
Preferred Stock Dividends (26) (26)
175,748
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (421) (421)
Unrealized Loss on
Minimum Pension Liability (7) (7)
Net Income 9,836 9,836
Total Comprehensive Income 9,408
MARCH 31, 2003 $137,214 $2,351 $ 76,782 $(31,191) $185,156
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 354,117 $ 353,087
Transmission 255,343 254,483
Distribution 446,150 445,486
General 109,200 111,679
Construction Work in Progress 39,991 37,012
Total Electric Utility Plant 1,204,801 1,201,747
Accumulated Depreciation and Amortization 518,631 521,792
NET ELECTRIC UTILITY PLANT 686,170 679,955
OTHER PROPERTY AND INVESTMENTS 1,065 1,213
LONG-TERM RISK MANAGEMENT ASSETS 4,433 2,248
CURRENT ASSETS:
Cash and Cash Equivalents 4,681 1,219
Advances to Affiliates 8,460 -
Accounts Receivable:
Customers 32,776 62,660
Affiliated Companies 37,796 43,632
Allowance for Uncollectible Accounts (4,728) (5,041)
Fuel Inventory 8,916 12,677
Materials and Supplies 10,029 9,574
Accrued Utility Revenues 5,591 6,829
Risk Management Assets 3,411 4,130
Prepayments and Other 1,198 1,070
TOTAL CURRENT ASSETS 108,130 136,750
REGULATORY ASSETS 44,165 45,097
DEFERRED CHARGES 27,481 11,912
TOTAL ASSETS $ 871,444 $ 877,175
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Accumulated Other Comprehensive Income (Loss) (31,191) (30,763)
Retained Earnings 76,782 71,942
Total Common Shareholder's Equity 185,156 180,744
Cumulative Preferred Stock Not Subject to
Mandatory Redemption 2,367 2,367
Long-term Debt 333,473 132,500
TOTAL CAPITZALIZATION 520,996 315,611
OTHER NONCURRENT LIABILITIES 41,859 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 17,297 32,714
Accounts Payable - Affiliated Companies 37,152 76,217
Customer Deposits 320 117
Taxes Accrued 25,425 3,697
Interest Accrued 4,847 2,776
Risk Management Liabilities 4,761 3,801
Other 8,237 17,414
TOTAL CURRENT LIABILITIES 122,075 342,143
DEFERRED INCOME TAXES 113,465 117,521
DEFERRED INVESTMENT TAX CREDITS 21,130 21,510
LONG-TERM RISK MANAGEMENT LIABILITIES 2,300 557
REGULATORY LIABILITIES AND DEFERRED CREDITS 49,619 50,972
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $871,444 $877,175
See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 9,836 $ 3,992
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 9,532 11,569
Deferred Income Taxes (5,666) (226)
Deferred Investment Tax Credits (380) (318)
Cumulative Effect of Accounting Changes (3,071) -
Mark-to-Market of Risk Management Contracts 608 (213)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) 35,407 (28,456)
Fuel, Materials and Supplies 3,306 (906)
Accrued Utility Revenues 1,238 474
Accounts Payable (54,482) (1,423)
Taxes Accrued 21,728 4,205
Fuel Recovery - (1,384)
Deferred Property Taxes (10,868) (9,525)
Change in Other Assets (4,593) (3,068)
Change in Other Liabilities 4,927 (1,033)
Net Cash Flows From (Used For) Operating Activities 7,522 (26,312)
INVESTING ACTIVITIES:
Construction Expenditures (10,197) (7,531)
Other - -
Net Cash Flows Used For Investing Activities (10,197) (7,531)
FINANCING ACTIVITIES:
Change in Short-term Debt (net) (125,000) -
Issuance of Long-term Debt 225,000 -
Change in Advances to/from Affiliates (net) (88,867) 38,720
Dividends Paid on Common Stock (4,970) (6,749)
Dividends Paid on Cumulative Preferred Stock (26) (26)
Net Cash Flows From Financing Activities 6,137 31,945
Net Increase (Decrease) in Cash and Cash Equivalents 3,462 (1,898)
Cash and Cash Equivalents at Beginning of Period 1,219 2,454
Cash and Cash Equivalents at End of Period $ 4,681 $ 556
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,021,000 and
$2,097,000 and for income taxes was $(8,873,000) and $(1,575,000) in 2003 and
2002, respectively.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
APCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 925,000 retail customers in southwestern
Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool,
shares in the revenues and cost of the AEP Power Pool's wholesale sales to
neighboring utility systems and power marketing transactions. APCo also sells
wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of revenues and costs.
Results of Operations
Net Income of $156.4 million in the first quarter of 2003 included income from
the Cumulative Effect of Accounting Changes of $77.3 million (see Note 3).
Income Before Cumulative Effect of Accounting Changes increased $23.8 million or
43% primarily due to an improvement in earnings from retail and AEP Power Pool
sales resulting from the interaction of plant availability, the colder winter
weather and higher margins. APCo, as a member of the AEP Power Pool, shares in
the revenues and costs of marketing and activities conducted on its behalf by
the AEP Power Pool. This increase was partially offset by a decline in
Nonoperating Income.
Changes in Operating Revenues
The following analyzes the changes in operating revenues:
(in millions) %
Electric Generation $56.0 21
Electric Transmission and
Distribution 3.5 2
Sales to AEP Affiliates 14.1 33
Total Operating Revenues $73.6 16
The increase in Operating Revenues was due primarily to higher Electric
Generation sales and Sales to AEP Affiliates reflecting the more severe winter
weather of 2003 and an increase in the volume of AEP Power Pool transactions.
Heating degree days were up 18% over the prior year which resulted in an
increase in Residential KWH sales of 16% as well as a 10% increase in total
Retail sales. Additionally, APCo's relative share of the AEP Power Pool revenues
(as well as expenses) for February and March, 2003 increased over the prior
period as a result of APCo reaching a new peak demand in January 2003.
Changes in Operating Expenses
Operating expenses increased 11% in the first quarter of 2003 over the prior
year. The changes in the components of operating expenses were:
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $12.4 12
Purchased Electricity for Resale 3.6 27
Purchased Electricity from AEP
Affiliates 19.9 33
Other Operation (4.8) (7)
Maintenance 6.9 27
Depreciation and Amortization (10.8) (23)
Taxes Other Than Income Taxes 0.1 -
Income Taxes 15.2 44
Total Operating Expenses $42.5 11
Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as KWH generated increased 7%.
Purchased Electricity for Resale increased in the first quarter of 2003 as
Retail KWH sales outpaced net generation. Purchased Electricity from AEP
Affiliates increased due to higher charges resulting from the increased of all
volume and the increase in APCo's share of the AEP Power Pool.
The decline in Other Operation expense was primarily due to decreased
employee-related expenses in the first quarter of 2003 reflecting the
cost-saving effects of the Sustained Earnings Improvement Initiative (see Note
9).
The increase in Maintenance expense is due to increased distribution line
maintenance caused by severe winter storm damage in 2003 and increased plant
maintenance primarily at the Sporn plant.
Depreciation and Amortization expense decreased primarily due to reduced expense
attributable to the adoption of SFAS 143. Effective January 1, 2003 the
generation depreciation rate for APCo's non-regulated operations was reduced to
exclude the non-ARO removal cost portion that was included in the depreciation
rate. Additionally, APCo had 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 accounting for the West Virginia
jurisdiction (see Note 6 for further discussion of the return to SFAS 71
accounting). Amortization costs of transition regulatory assets had been
accelerated since July 2000 in connection with the discontinuance of SFAS 71 in
APCo's West Virginia jurisdiction. At that time net generation-related
regulatory assets were transferred to the distribution portion of the business
commensurate with their recovery through regulated rates.
The increase in operating Income Taxes is due to an increase in pre-tax
operating book income.
Other Changes
The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.
The Nonoperating Income Tax Credit in 2003 reflects the tax benefits associated
with the reduction in Nonoperating Income.
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 of 02-3
(see Notes 2 and 3).
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $323,484 $267,475
Electric Transmission and Distribution 155,849 152,324
Sales to AEP Affiliates 56,895 42,806
TOTAL OPERATING REVENUES 536,228 462,605
OPERATING EXPENSES:
Fuel for Electric Generation 119,865 107,490
Purchased Electricity for Resale 17,118 13,516
Purchased Electricity from AEP Affiliates 80,720 60,780
Other Operation 62,115 66,959
Maintenance 32,738 25,851
Depreciation and Amortization 36,008 46,772
Taxes Other Than Income Taxes 25,079 24,995
Income Taxes 49,901 34,688
TOTAL OPERATING EXPENSES 423,544 381,051
OPERATING INCOME 112,684 81,554
NONOPERATING INCOME (LOSS) (4,484) 5,084
NONOPERATING EXPENSES 3,674 3,645
NONOPERATING INCOME TAX EXPENSE (CREDIT) (3,733) 264
INTEREST CHARGES 29,106 27,388
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 79,153 55,341
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 77,257 -15 15
NET INCOME 156,410 55,341
PREFERRED STOCK DIVIDEND REQUIREMENTS 984 503
EARNINGS APPLICABLE TO COMMON STOCK $155,426 $ 54,838
The common stock of APCo is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND872 872
-------
TOTAL COMPREHENSIVE INCOME (UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $260,458 $715,786 $150,797 $ (340) $1,126,701
Common Stock Dividends (30,984) (30,984)
Preferred Stock Dividends (361) (361)
Capital Stock Expense 142 (142) -
1,095,356
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges
143 143
Net Income 55,341 55,341
Total Comprehensive Income 55,484
MARCH 31, 2002 $260,458 $715,928 $174,651 $ (197) $1,150,840
JANUARY 1,736
------- ------- ------- ------ -------
SEPTEMBER 30, 2003 $260,458 $717,242 $260,439 $(72,082) $1,166,057
Common Stock Dividends (32,066) (32,066)
Preferred Stock Dividends (361) (361)
Capital Stock Expense 623 (623) -
SFAS 71 Reapplication 162 162
1,133,792
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (12,518) (12,518)
Net Income 156,410 156,410
Total Comprehensive Income 143,892
MARCH 31, 2003 $260,458 $718,027 $383,799 $(84,600) $1,277,684
See Notes to Financial Statements beginning on page L-1.$2,626 $4,184 $2,393 $(745) $8,458
======= ======= ======= ====== =======
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,256,941 $2,245,945
Transmission 1,218,056 1,218,108
Distribution 1,964,405 1,951,804
General 275,416 272,901
Construction Work in Progress 234,995 206,545
Total Electric Utility Plant 5,949,813 5,895,303
Accumulated Depreciation and Amortization 2,317,009 2,424,607
NET ELECTRIC UTILITY PLANT 3,632,804 3,470,696
OTHER PROPERTY AND INVESTMENTS 53,149 54,653
LONG-TERM RISK MANAGEMENT ASSETS 130,451 115,748
CURRENT ASSETS:
Cash and Cash Equivalents 10,449 4,285
Advances to Affiliates 87,859 -
Accounts Receivable:
Customers 164,050 132,266
Affiliated Companies 88,948 122,665
Miscellaneous 29,217 28,629
Allowance for Uncollectible Accounts (2,596) (13,439)
Fuel Inventory 39,817 53,646
Materials and Supplies 61,697 59,886
Accrued Utility Revenues 7,620 30,948
Risk Management Assets 135,545 94,238
Prepayments and Other 13,716 13,396
TOTAL CURRENT ASSETS 636,322 526,520
REGULATORY ASSETS 407,687 395,553
DEFERRED CHARGES 67,273 64,677
TOTAL ASSETS $4,927,686 $4,627,847
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 718,027 717,242
Accumulated Other Comprehensive Income (Loss) (84,600) (72,082)
Retained Earnings 383,799 260,439
Total Common Shareowner's Equity 1,277,684 1,166,057
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,739,210 1,738,854
TOTAL CAPITALIZATION 3,045,544 2,933,561
OTHER NONCURRENT LIABILITIES 191,764 173,438
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,007 155,007
Advances from Affiliates - 39,205
Accounts Payable - General 153,667 141,546
Accounts Payable - Affiliated Companies 72,179 98,374
Taxes Accrued 88,442 29,181
Customer Deposits 35,245 26,186
Interest Accrued 39,222 22,437
Risk Management Liabilities 118,979 69,001
Other 63,607 79,832
TOTAL CURRENT LIABILITIES 726,348 660,769
DEFERRED INCOME TAXES 749,572 701,801
DEFERRED INVESTMENT TAX CREDITS 33,936 33,691
LONG-TERM RISK MANAGEMENT LIABILITIES 79,901 44,517
REGULATORY LIABILITIES AND DEFERRED CREDITS 100,621 80,070
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $4,927,686 $4,627,847
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $156,410 $ 55,341
Adjustments for Noncash Items:
Cumulative Effect of Accounting Changes (77,257) -
Depreciation and Amortization 36,008 46,800
Deferred Income Taxes 1,005 (3,644)
Deferred Investment Tax Credits 245 (1,098)
Deferred Power Supply Costs (net) 63,837 352
Mark to Market of Risk Management Contracts 5,383 (6,653)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (9,498) (51,419)
Fuel, Materials and Supplies 12,018 12,659
Accrued Utility Revenues 23,328 7,013
Accounts Payable (14,074) 11,456
Taxes Accrued 59,261 29,129
Interest Accrued 16,785 17,516
Incentive Plan Accrued (9,595) (9,362)
Change in Operating Reserves 20,095 1,541
Rate Stabilization Deferral (75,601) -
Change in Other Assets (14,446) (7,043)
Change in Other Liabilities 26,114 9,187
Net Cash Flows From Operating Activities 220,018 111,775
INVESTING ACTIVITIES:
Construction Expenditures (56,627) (62,685)
Proceeds from Sale of Property and Other 2,264 583
Net Cash Flows Used For Investing Activities (54,363) (62,102)
FINANCING ACTIVITIES:
Change in Advances From Affiliates (127,064) (31,991)
Dividends Paid on Common Stock (32,066) (30,984)
Dividends Paid on Cumulative Preferred Stock (361) (361)
Net Cash Flows Used For Financing Activities (159,491) (63,336)
Net Increase (Decrease) in Cash and Cash Equivalents 6,164 (13,663)
Cash and Cash Equivalents at Beginning of Period 4,285 13,663
Cash and Cash Equivalents at End of Period $ 10,449 $ -
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $11,191,000 and
$9,222,000 and for income taxes was $(11,498,000) and $9,593,000 in 2003 and
2002, respectively.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
Columbus Southern Power Company (CSPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 689,000 retail customers in central and southern Ohio. CSPCo, as a
member of the AEP Power Pool, shares in the revenues and costs of the AEP Power
Pool's wholesale sales to neighboring utilities and power marketing
transactions. CSPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivery to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing AEP
Power Pool revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
Results of Operations
Net Income increased $32 million or 94% including a $27 million Cumulative
Effect of Accounting Changes in the first quarter of 2003 (see Note 3). Net
Income Before Cumulative Effect increased $5 million or 13% due to an
improvement in earnings from retail and AEP Power Pool sales resulting from the
interactions of plant availability, colder winter weather and higher margins.
CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of
marketing and activities conducted on its behalf by the AEP Power Pool.
Changes in Operating Revenues
The following analyzes the increase in operating revenue components:
(in millions) %
Electric Generation $20.0 10
Electric Transmission and
Distribution 11.3 10
Sales to AEP Affiliates 13.1 170
Total Operating Revenues $44.4 14
The increase in Electric Generation was driven largely by a rise in demand due
to more severe winter weather in 2003 versus 2002. Heating degree days for the
first quarter of 2003 were up 24% from the same quarter last year which resulted
in 14% higher Residential KWH sales as well as a 5% increase in Commercial KWH
Sales.
CSPCo's share of AEP Power Pool revenues and expenses for 2003 increased over
the prior year as a result of an increase in the volume of the AEP Power Pool
sales. CSPCo's share of AEP Power Pool sales increased 5%.
Changes in Operating Expenses
Operating Expenses increased 13% in 2003. The increases in the components of
Operating Expenses were:
(in millions) %
Fuel for Electric Generation $ 6.4 14
Purchased Electricity for Resale 0.5 13
Purchased Electricity from AEP Affiliates
10.6 15
Other Operation 2.5 5
Maintenance 0.4 3
Depreciation and Amortization 1.0 3
Taxes Other Than Income Taxes 5.3 18
Income Taxes 8.1 47
Total Operating Expenses $34.8 13
Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as net KWH generation increased
13%.
Purchased Electricity from AEP Affiliates was higher due to increases in energy
purchased from the AEP Power Pool resulting from a high volume of AEP Power Pool
sales and greater capacity charges.
The increase in Taxes Other Than Income Taxes was a result of increases in
property taxes and state excise taxes.
An increase in operating Income Taxes is due to an increase in pre-tax operating
book income.
Other Changes
The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.
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
Notes 2 and 3).
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $214,821 $194,824
Electric Transmission and Distribution 123,616 112,324
Sales to AEP Affiliates 20,768 7,678
TOTAL OPERATING REVENUES 359,205 314,826
OPERATING EXPENSES:
Fuel for Electric Generation 52,043 45,650
Purchased Electricity for Resale 4,198 3,729
Purchased Electricity from AEP Affiliates 82,149 71,582
Other Operation 56,385 53,861
Maintenance 14,559 14,140
Depreciation and Amortization 33,737 32,736
Taxes Other Than Income Taxes 35,608 30,276
Income Taxes 25,375 17,304
TOTAL OPERATING EXPENSES 304,054 269,278
OPERATING INCOME 55,151 45,548
NONOPERATING INCOME (LOSS) (7,015) 5,074
NONOPERATING EXPENSES 1,862 1,624
NONOPERATING INCOME TAX EXPENSE (CREDIT) (5,547) 1,347
INTEREST CHARGES 13,462 13,793
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 38,359 33,858
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 27,283 -
NET INCOME 65,642 33,858
PREFERRED STOCK DIVIDEND REQUIREMENTS 254 181
EARNINGS APPLICABLE TO COMMON STOCK $ 65,388 $ 33,677
The common stock of CSPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on Page L-1
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $41,026 $574,369 $176,103 $ - $791,498
Common Stock Dividends Declared (21,766) (21,766)
Preferred Stock Dividends Declared (175) (175)
Capital Stock Expense 253 (254) (1)
769,556
Comprehensive Income:
Other Comprehensive Income - -
Net Income 33,858 33,858
Total Comprehensive Income 33,858
MARCH 31, 2002 $41,026 $574,622 $187,766 $ - $803,414
JANUARY 1, 2003 $41,026 $575,384 $290,611 $(59,357) $847,664
Common Stock Dividends Declared (38,311) (38,311)
Capital Stock Expense 254 (254) -
809,353
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (7,343) (7,343)
Net Income 65,642 65,642
Total Comprehensive Income 58,299
MARCH 31, 2003 $41,026 $575,638 $317,688 $(66,700) $867,652
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,591,772 $1,582,627
Transmission 413,327 413,286
Distribution 1,214,588 1,208,255
General 155,854 165,025
Construction Work in Progress 106,447 98,433
Total Electric Utility Plant 3,481,988 3,467,626
Accumulated Depreciation and Amortization 1,428,761 1,465,174
NET ELECTRIC UTILITY PLANT 2,053,227 2,002,452
OTHER PROPERTY AND INVESTMENTS 34,589 35,759
LONG-TERM RISK MANAGEMENT ASSETS 76,680 77,810
CURRENT ASSETS:
Cash and Cash Equivalents 7,968 1,479
Advances to Affiliates 87,460 31,257
Accounts Receivable:
Customers 55,642 49,566
Affiliated Companies 39,880 54,518
Miscellaneous 19,546 22,005
Allowance for Uncollectible Accounts (579) (634)
Fuel 15,757 24,844
Materials and Supplies 40,928 40,339
Accrued Utility Revenues 6,964 12,671
Risk Management Assets 79,692 63,348
Prepayments and Other 9,221 7,308
TOTAL CURRENT ASSETS 362,479 306,701
REGULATORY ASSETS 252,940 257,682
DEFERRED CHARGES 77,510 72,836
TOTAL ASSETS $2,857,425 $2,753,240
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 575,638 575,384
Accumulated Other Comprehensive Loss (66,700) (59,357)
Retained Earnings 317,688 290,611
Total Common Shareholder's Equity 867,652 847,664
Long-term Debt - General 747,264 418,626
Long-term Debt - Affiliated Companies - 160,000
TOTAL CAPITALIZATION 1,614,916 1,426,290
OTHER NONCURRENT LIABILITIES 92,207 95,460
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 168,500 43,000
Short-term Debt - Affiliated Companies 40,000 290,000
Accounts Payable - General 86,989 89,736
Accounts Payable - Affiliated Companies 45,099 81,599
Taxes Accrued 123,989 112,172
Interest Accrued 13,692 9,798
Risk Management Liabilities 69,939 46,375
Other 51,934 36,790
TOTAL CURRENT LIABILITIES 600,142 709,470
DEFERRED INCOME TAXES 448,836 437,771
DEFERRED INVESTMENT TAX CREDITS 33,144 33,907
LONG-TERM RISK MANAGEMENT LIABILITIES 46,967 29,926
DEFERRED CREDITS AND REGULATORY LIABILITIES 21,213 20,416
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $2,857,425 $2,753,240
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
(in thousands)
2003 2002
OPERATING ACTIVITIES:
Net Income $ 65,642 $ 33,858
Adjustments for Noncash Items:
Cumulative Effect of Accounting Changes (27,283) -
Depreciation and Amortization 33,737 32,786
Deferred Income Taxes (3,095) (313)
Deferred Investment Tax Credits (763) (778)
Mark to Market of Risk Management Contracts 10,958 (5,849)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 10,966 (42,207)
Fuel, Materials and Supplies 8,498 3,636
Accrued Utility Revenues 5,707 (5,247)
Accounts Payable (39,247) 7,349
Taxes Accrued 11,817 (19,947)
Interest Accrued 3,894 3,607
Change in Other Assets (5,740) 992
Change in Other Liabilities 6,991 3,505
Net Cash Flows From Operating Activities 82,082 11,392
INVESTING ACTIVITIES:
Construction Expenditures (27,269) (24,807)
Proceeds from Sale of Property 190 389
Net Cash Flows Used For Investing Activities (27,079) (24,418)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 -
Advances from (to) Affiliates (56,203) 29,106
Retirement of Long-term Debt (204,000) -
Change in Short-term Debt (250,000) -
Dividends Paid on Common Stock (38,311) (21,766)
Dividends Paid on Cumulative Preferred Stock (175)
Net Cash Flows From (Used For) Financing Activities
(48,514) 7,165
Net Increase (Decrease) in Cash and Cash Equivalents 6,489 (5,861)
Cash and Cash Equivalents at Beginning of Period 1,479 12,358
Cash and Cash Equivalents at End of Period $ 7,968 $ 6,497
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,219,000 and
$9,725,000 and for income taxes was ($16,019,000) and $11,198,000 in 2003 and
2002, respectively.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
I&M is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 571,000 retail customers in its service
territory in northern and eastern Indiana and a portion of southwestern
Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the
costs of the AEP Power Pool's wholesale sales to neighboring utilities and power
marketers. I&M also sells wholesale power to municipalities and electric
cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among the AEP
Power Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for the out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is each company's
member load ratio (MLR) which determines each company's percentage share of
revenues and costs.
Under the terms of unit power agreements, I&M purchases AEGCo's 50% share of the
2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is
an affiliate that is not a member of the AEP Power Pool. An agreement between
AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of AEGCo's 50%
share of Rockport Plant capacity. If AEP's restructuring settlement agreement
filed with the FERC becomes operative, the KPCo agreement extends until December
31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant
Unit 2.
Results of Operations
Net Income Before Cumulative Effect of Accounting Change increased $20 million
or 178% due primarily to increased sales as a result of higher availability of
I&M's Cook Plant and Rockport Plant in 2003 as compared to 2002. In addition, an
improvement in earnings from retail and AEP Power Pool sales resulted from the
interaction of plant availability, the more severe winter conditions and higher
margins. I&M, as a member of the AEP Power Pool, shares in the revenues and
costs of the marketing activities conducted on its behalf by the AEP Power Pool.
Changes in Operating Revenues
Operating Revenues increased 19% due primarily to higher Electric Generation
sales and Sales to AEP Affiliates reflecting the colder winter weather of 2003,
an increase in AEP Power Pool transactions shared with I&M and an increase in
sales to the AEP Power Pool. The following analyzes the increases in Operating
Revenues:
(in millions) %
Electric Generation $38.6 16
Electric Transmission and
Distribution 6.2 9
Sales to AEP Affiliates 21.6 46
Total Operating Revenues $66.4 19
The increase in Electric Generation revenues was due to an increase in sales
reflecting a colder winter. Heating degree days were up 28% over the prior year
which resulted in an increase in Residential KWH sales of 13% as well as a 5%
increase in total retail sales. I&M's share of the AEP Power Pool revenues (as
well as expenses) during 2003 increased over the prior year as a result of an
increase in the volume of the AEP Power Pool.
Revenues from Sales to AEP Affiliates increased significantly reflecting more
power being available for sale in 2003 as one unit of the Cook Nuclear Plant was
shutdown for refueling and both units of Rockport Plant were scheduled for
planned boiler maintenance in 2002. AEP Power Pool members are compensated for
the out-of-pocket costs of energy delivered to the AEP Power Pool and charged
for energy received from the AEP Power Pool. With the outages in 2002, I&M's
available generation increased in 2003 resulting in more power being delivered
to the AEP Power Pool.
Changes in Operating Expenses
Operating Expenses increased 12% in 2003. The changes in the components of
Operating Expenses were:
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $18.9 35
Purchased Electricity for Resale 1.0 19
Purchased Electricity from AEP Affiliates
12.4 23
Other Operation (10.4) (9)
Maintenance 0.3 1
Depreciation and Amortization 1.9 4
Taxes Other Than Income Taxes (1.4) (8)
Income Taxes 15.0 250
Total Operating Expenses $37.7 12
Fuel for Electric Generation increased primarily due to an increase in
generation reflecting the plant outages in 2002.
Purchased Electricity from AEP Affiliates increased due to higher availability
of the Rockport Plant in 2002, as I&M is required to purchase a portion of
AEGCo's Rockport Plant generation under their unit power agreement. AEGCo's
share of generation at the Rockport Plant increased 50% in 2003.
Other Operation expense decreased due to cost reduction efforts instituted in
the fourth quarter of 2002 and costs incurred during the outages occurring
during the first quarter of 2002.
The 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.
Income Taxes attributable to operations increased significantly due to an
increase in pre-tax operating income.
Other Changes
The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to exit those risk management activities in areas outside of its
traditional market area.
The decrease in Nonoperating Income Tax Expense is a result of the decline in
pre-tax nonoperating income.
Cumulative Effect of Accounting Change
The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Notes 2 and 3).
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $273,008 $234,446
Electric Transmission and Distribution 76,779 70,580
Sales to AEP Affiliates 68,811 47,209
TOTAL OPERATING REVENUES 418,598 352,235
OPERATING EXPENSES:
Fuel for Electric Generation 73,094 54,156
Purchased Electricity for Resale 6,282 5,282
Purchased Electricity from AEP Affiliates 65,898 53,507
Other Operation 101,381 111,766
Maintenance 31,367 31,043
Depreciation and Amortization 43,726 41,866
Taxes Other Than Income Taxes 16,821 18,241
Income Taxes 21,039 6,011
TOTAL OPERATING EXPENSES 359,608 321,872
OPERATING INCOME 58,990 30,363
NONOPERATING INCOME 3,619 17,004
NONOPERATING EXPENSES 12,935 13,310
NONOPERATING INCOME TAX EXPENSE (CREDIT) (4,451) (425)
INTEREST CHARGES 23,438 23,424
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 30,687 11,058
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (3,160) -
NET INCOME 27,527 11,058
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,149 1,155
EARNINGS APPLICABLE TO COMMON STOCK $ 26,378 $ 9,903
The common stock of I&M is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $56,584 $733,216 $ 74,605 $(3,835) $ 860,570
Preferred Stock Dividends (1,122) (1,122)
Capital Stock Expense 33 (33) -
859,448
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Cash Flow Interest Rate Hedge 1,259 1,259
Net Income 11,058 11,058
Total Comprehensive Income 12,317
MARCH 31, 2002 $56,584 $733,249 $ 84,508 $(2,576) $ 871,765
JANUARY 1, 2003 $56,584 $858,560 $143,996 $(40,487) $1,018,653
Common Stock Dividends (10,000) (10,000)
Preferred Stock Dividends (1,115) (1,115)
Capital Stock Expense 34 (34) -
1,007,538
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (7,857) (7,857)
Net Income 27,527 27,527
Total Comprehensive Income 19,670
MARCH 31, 2003 $56,584 $858,594 $160,374 $(48,344) $1,027,208
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,858,230 $2,768,463
Transmission 979,559 971,599
Distribution 928,699 921,835
General (including nuclear fuel) 208,856 220,137
Construction Work in Progress 148,218 147,924
Total Electric Utility Plant 5,123,562 5,029,958
Accumulated Depreciation and Amortization 2,645,331 2,568,604
NET ELECTRIC UTILITY PLANT 2,478,231 2,461,354
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 870,689 870,754
LONG-TERM RISK MANAGEMENT ASSETS 80,073 83,265
OTHER PROPERTY AND INVESTMENTS 115,837 120,941
CURRENT ASSETS:
Cash and Cash Equivalents 6,520 3,237
Advances to Affiliates 228,775 191,226
Accounts Receivable:
Customers 77,278 67,333
Affiliated Companies 131,332 122,489
Miscellaneous 18,401 30,468
Allowance for Uncollectible Accounts (574) (578)
Fuel 30,586 32,731
Materials and Supplies 96,875 95,552
Risk Management Assets 85,221 68,148
Prepayments and Other 16,213 18,410
TOTAL CURRENT ASSETS 690,627 629,016
REGULATORY ASSETS 304,988 348,212
DEFERRED CHARGES 85,494 73,649
TOTAL ASSETS $4,625,939 $4,587,191
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 858,594 858,560
Accumulated Other Comprehensive Income (Loss) (48,344) (40,487)
Retained Earnings 160,374 143,996
Total Common Shareowner's Equity 1,027,208 1,018,653
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,101 8,101
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,333,013 1,587,062
TOTAL CAPITALIZATION 2,433,267 2,678,761
OTHER NONCURRENT LIABILITIES:
Asset Retirement Obligations 525,116 -
Nuclear Decommissioning - 620,672
Other 131,140 138,965
TOTAL OTHER NONCURRENT LIABILITIES 656,256 759,637
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 285,000 30,000
Accounts Payable:
General 108,331 125,048
Affiliated Companies 60,845 93,608
Taxes Accrued 90,725 71,559
Interest Accrued 25,786 21,481
Obligations Under Capital Leases 6,258 8,229
Risk Management Liabilities 73,799 48,568
Other 95,692 92,822
TOTAL CURRENT LIABILITIES 746,436 491,315
DEFERRED INCOME TAXES 326,438 356,197
DEFERRED INVESTMENT TAX CREDITS 95,874 97,709
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 72,958 73,885
LONG-TERM RISK MANAGEMENT LIABILITIES 48,402 32,261
DEFERRED CREDITS AND REGULATORY LIABILITIES 246,308 97,426
CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $4,625,939 $4,587,191
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 27,527 $ 11,058
Adjustments for Noncash Items:
Cumulative Effect of Accounting Change 3,160 -
Depreciation and Amortization 43,726 42,184
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)
9,410 (24,130)
Unrecovered Fuel and Purchased Power Costs 9,375 9,375
Amortization of Nuclear Outage Costs 10,000 10,000
Deferred Income Taxes (12,367) (7,132)
Deferred Investment Tax Credits (1,835) (1,845)
Mark-to-Market of Risk Management Contracts 10,543 (3,708)
Deferred Property Taxes (9,116) (8,409)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (6,725) (58,316)
Fuel, Materials and Supplies 822 5,522
Accounts Payable (49,480) (10,779)
Taxes Accrued 19,166 21,391
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 21,178 8,328
Change in Other Liabilities (13,679) 675
Net Cash Flows From Operating Activities 80,169 12,678
INVESTING ACTIVITIES:
Construction Expenditures (28,234) (26,398)
Other 12 -
Net Cash Flows Used For Investing Activities (28,222) (26,398)
FINANCING ACTIVITIES:
Change in Advances from (to) Affiliates (net) (37,549) 8,887
Dividends Paid on Common Stock (10,000) -
Dividends Paid on Cumulative Preferred Stock (1,115) (1,122)
Net Cash Flows From (Used For) Financing Activities (48,664) 7,765
Net Increase (Decrease) in Cash and Cash Equivalents 3,283 (5,955)
Cash and Cash Equivalents at Beginning of Period 3,237 16,804
Cash and Cash Equivalents at End of Period $ 6,520 $ 10,849
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $18,211,000 and
$15,090,000 and for income taxes was $20,011,000 and $(470,000) in 2003 and
2002, respectively.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
KPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power serving 174,000 retail customers in eastern
Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and
costs of the AEP Power Pool's wholesale sales to neighboring utility systems and
power marketing transactions. KPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve-month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
KPCo has a unit power agreement with AEGCo, an affiliated company, which expires
in 2004. The agreement provides for KPCo to purchase 15% of the total output of
the two unit 2,600-mw capacity Rockport Plant. Under the unit power agreement,
there is a demand charge for the right to receive the power, which is payable
even if the power is not taken. The amount of the demand charge is such that
when added to other amounts received by AEGCo, it will enable AEGCo to recover
all its fixed expenses including a FERC-approved rate of return on common
equity.
Results of Operations
Net Income of $9.9 million in the first quarter of 2003 included a loss from the
Cumulative Effect of Accounting Change of $1.1 million due to the adoption of
EITF 02-3. Income Before Cumulative Effect of Accounting Change increased $0.8
million or 8% primarily due to an improvement in earnings from retail and AEP
Power Pool sales resulting from the interaction of plant availability, the more
severe winter weather and higher margins in 2003 versus 2002. KPCo, a member of
the Power Pool, shares in the revenues and costs of marketing and activities
conducted on its behalf by the AEP Power Pool.
Changes in Operating Revenues
The following analyzes the increase in operating revenues:
(in millions) %
Electric Generation $10.3 17
Electric Transmission and Distribution 0.5 2
Sales to AEP Affiliates 2.1 35
Total Operating Revenues $12.9 13
The increase in Operating Revenues is due to an increase in residential sales
reflecting increased demand due to the more severe weather in 2003 versus 2002
and higher volume in the AEP Power Pool of transactions. Heating degree days
were up approximately 18% resulting in a 12% increase in Residential KWH sold.
This increase was partially offset by reduced industrial sales reflecting the
slowdown in the economy. Overall retail sales were up 3% over 2002.
Changes in Operating Expenses
Changes in the components of Operating Expenses were:
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $(3.8) (18)
Purchased Electricity from AEP Affiliates 8.5 29
Other Operation (0.2) (2)
Maintenance 2.2 49
Depreciation and Amortization 0.5 6
Taxes Other Than Income Taxes 0.2 11
Income Taxes 1.2 22
Total Operating Expenses $ 8.6 10
Fuel for Electric Generation decreased due to unplanned outages in 2003 at
KPCo's Big Sandy Plant resulting in a 26% decline in net generation. Purchased
Electricity from AEP Affiliates increased primarily to support Electric
Generation sales. Increased purchases of electricity from the Rockport Plant,
which had been in an outage during the first quarter of 2002, also contributed
to the increased expense.
Maintenance expense increased primarily due to distribution line maintenance
resulting from a major ice storm in February 2003. A three week outage at the
Big Sandy plant also contributed to increased Maintenance expenses.
The increase in operating Income Taxes is due to an increase in pre-tax
Operating Income.
Other Changes
The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.
The increase in Nonoperating Income Tax Credits reflects the tax benefits
associated with the reduction in Nonoperating Income.
Cumulative Effect of Accounting Change
The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Notes 2 and 3).
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $ 69,165 $ 58,887
Electric Transmission and Distribution 34,794 34,276
Sales to AEP Affiliates 8,135 6,022
TOTAL OPERATING REVENUES 112,094 99,185
OPERATING EXPENSES:
Fuel for Electric Generation 17,947 21,767
Purchased Electricity from AEP Affiliates 37,395 28,941
Other Operation 12,137 12,351
Maintenance 6,765 4,549
Depreciation and Amortization 8,712 8,257
Taxes Other Than Income Taxes 2,365 2,135
Income Taxes 6,939 5,701
TOTAL OPERATING EXPENSES 92,260 83,701
OPERATING INCOME 19,834 15,484
NONOPERATING INCOME (LOSS) (2,415) 1,642
NONOPERATING EXPENSES 232 570
NONOPERATING INCOME TAX CREDIT 558 190
INTEREST CHARGES 6,724 6,500
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 11,021 10,246
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (1,134) -
NET INCOME $ 9,887 $ 10,246
The common stock of KPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $50,450 $158,750 $48,833 $(1,903) $256,130
Common Stock Dividends (7,044) (7,044)
249,086
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power
Hedges 516 516
Net Income 10,246 10,246
Total Comprehensive Income 10,762
MARCH 31, 2002 $50,450 $158,750 $52,035 $(1,387) $259,848
JANUARY 1, 2003 $50,450 $208,750 $48,269 $(9,451) $298,018
Common Stock Dividends (5,482) (5,482)
292,536
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (2,865) (2,865)
Net Income 9,887 9,887
Total Comprehensive Income 7,022
MARCH 31, 2003 $50,450 $208,750 $52,674 $(12,316) $299,558
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 284,401 $ 275,121
Transmission 374,120 373,639
Distribution 415,725 414,281
General 67,296 67,449
Construction Work in Progress 179,635 165,129
Total Electric Utility Plant 1,321,177 1,295,619
Accumulated Depreciation and Amortization 396,014 397,304
NET ELECTRIC UTILITY PLANT 925,163 898,315
OTHER PROPERTY AND INVESTMENTS 6,585 6,904
LONG-TERM RISK MANAGEMENT ASSETS 29,686 29,871
CURRENT ASSETS:
Cash and Cash Equivalents 1,465 2,304
Accounts Receivable:
Customers 25,156 22,044
Affiliated Companies 13,692 23,802
Miscellaneous 3,254 2,889
Allowance for Uncollectible Accounts (563) (192)
Fuel 12,158 10,817
Materials and Supplies 16,125 16,127
Accrued Utility Revenues 6,529 5,301
Accrued Tax Benefit - 1,253
Risk Management Assets 30,853 24,320
Prepayments and Other 2,110 2,127
TOTAL CURRENT ASSETS 110,779 110,792
REGULATORY ASSETS 102,689 101,976
DEFERRED CHARGES 16,084 16,818
TOTAL ASSETS $1,190,986 $1,164,676
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 208,750 208,750
Accumulated Other Comprehensive Income (Loss) (12,316) (9,451)
Retained Earnings 52,674 48,269
Total Common Shareowner's Equity 299,558 298,018
Long-term Debt 391,665 391,632
Long-term Debt - Affiliated Companies 60,000 60,000
TOTAL CAPITALIZATION 751,223 749,650
OTHER NONCURRENT LIABILITIES 27,220 27,319
CURRENT LIABILITIES:
Long-term Debt Due Within One Year
- Affiliated Companies 15,000 15,000
Advances from Affiliates 46,071 23,386
Accounts Payable:
General 40,294 46,515
Affiliated Companies 25,052 44,035
Customer Deposits 10,345 8,048
Interest Accrued 7,987 6,471
Accrued Taxes 8,679 -
Risk Management Liabilities 27,076 17,803
Other 10,351 14,322
TOTAL CURRENT LIABILITIES 190,855 175,580
DEFERRED INCOME TAXES 179,059 178,313
DEFERRED INVESTMENT TAX CREDITS 8,871 9,165
LONG-TERM RISK MANAGEMENT LIABILITIES 18,183 11,488
REGULATORY LIABILITIES AND DEFERRED CREDITS 15,575 13,161
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $1,190,986 $1,164,676
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 9,887 $ 10,246
Adjustments for Noncash Items:
Cumulative Effect of Accounting Change 1,134 -
Depreciation and Amortization 8,712 8,257
Deferred Income Taxes 2,766 (556)
Deferred Investment Tax Credits (294) (295)
Deferred Fuel Costs (net) (388) 1,542
Mark-to-Market of Risk Management Contracts 3,500 (1,858)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 7,004 (14,598)
Fuel, Materials and Supplies (1,339) (1,759)
Accrued Utility Revenues (1,228) (2,921)
Accounts Payable (25,204) 5,618
Taxes Accrued 9,932 1,710
Change in Other Assets (474) 4,997
Change in Other Liabilities 2,765 435
Net Cash Flows From Operating Activities 16,773 10,818
INVESTING ACTIVITIES:
Construction Expenditures (35,025) (15,898)
Proceeds from Sales of Property and Other 210 -
Net Cash Flow Used for Investing Activities (34,815) (15,898)
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 22,685 10,594
Dividends Paid (5,482) (7,044)
Net Cash Flows From Financing Activities 17,203 3,550
Net Decrease in Cash and Cash Equivalents (839) (1,530)
Cash and Cash Equivalents at Beginning of Period 2,304 1,947
Cash and Cash Equivalents at End of Period $ 1,465 $ 417
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $7,975,000 and $6,328,000
in 2003 and 2002, respectively. Cash paid (received) for income taxes was
$(6,435,000) and $3,053,000 in 2003 and 2002, respectively. Noncash acquisitions
under capital leases were $22,000 in 2002.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
Ohio Power Company (OPCo) is a public utility engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
702,000 customers in the northwestern, east central, eastern and southern
sections of Ohio. As a member of the AEP Power Pool, OPCo shares in the revenues
and the costs of the AEP Power Pool's wholesale sales to neighboring utilities
and power marketing transactions. OPCo also sells wholesale power to Wheeling
Power Company, municipalities and electric cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR) which
determines each company's percentage share of AEP Power Pool revenues and costs.
Results of Operations
Net Income for the first quarter of 2003 increased $129 million or 201% compared
to the same quarter last year. This increase was due primarily to a $125 million
Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note
3). Net Income Before Cumulative Effect of Accounting Changes increased $4
million or 7% primarily due to an improvement in earnings from retail and AEP
Power Pool sales resulting from the interactions of plant availability, the
colder weather and higher margins. OPCo, as a member of the Power Pool, shares
in the revenues and costs of marketing and activities conducted on its behalf by
the AEP Power Pool.
Changes in Operating Revenues
The following analyzes the increases in operating revenue components:
(in millions) %
Electric Generation $35.1 13
Electric Transmission and Distribution
4.8 3
Sales to AEP Affiliates 30.1 27
Total Operating Revenues $70.0 13
The increase in Operating Revenues is due to a rise in revenue from Electric
Generation and Sales to AEP Affiliates. The increase was driven largely by an
increased demand due to more severe winter conditions in 2003 as compared to
2002, and an increase in the volume of AEP Power Pool transactions. Heating
degree days were up 25% over the prior year which resulted in 13% higher
residential KWH sales. OPCo's share of the AEP Power Pool revenues and expenses
for first quarter 2003 increased over the prior year as a result of an increase
in the overall volume of the AEP Power Pool. OPCo's share of AEP Power Pool
sales increased 19%.
Changes in Operating Expenses
Operating Expenses increased 13% in 2003. The changes in the components of
Operating Expenses were:
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $11.3 8
Purchased Electricity for Resale 1.8 10
Purchased Electricity from AEP Affiliates
8.5 60
Other Operation 2.9 3
Maintenance 6.5 22
Depreciation and Amortization (1.1) (2)
Taxes Other Than Income Taxes 1.3 3
Income Taxes 23.6 67
Total Operating Expenses $54.8 13
Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as net KWH generation increased
30%. Purchased Electricity for Resale increased due to the 4% increase in KWH
purchased to meet demand. Purchased Electricity from AEP Affiliates increased as
a result of additional MWH purchases and increased prices.
Maintenance expense increased primarily due to an increase in boiler plant
maintenance and distribution line maintenance caused by severe storm damage in
2003.
The increase in operating Income Taxes is due to an increase in pre-tax
operating book income and federal income tax adjustments.
Other Changes
The decrease in Nonoperating Income (Loss) is due to lower margins for power
sold outside of AEP's traditional marketing area reflecting reduced demand and
AEP's plan to reduce those types of transactions.
Nonoperating Expenses increased predominately as a result of costs incurred
related to the sale of our Switch Water Heater program. The decrease in
Nonoperating Income Tax Expense (Credit) is due to a decrease in pre-tax
nonoperating book income.
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
Notes 2 and 3).
OHIO POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $305,035 $269,978
Electric Transmission and Distribution 145,852 141,040
Sales to AEP Affiliates 139,744 109,634
TOTAL OPERATING REVENUES 590,631 520,652
OPERATING EXPENSES:
Fuel for Electric Generation 153,648 142,336
Purchased Electricity for Resale 19,392 17,629
Purchased Electricity from AEP Affiliates 22,783 14,227
Other Operation 92,981 90,114
Maintenance 35,457 28,988
Depreciation and Amortization 61,551 62,621
Taxes Other Than Income Taxes 47,155 45,839
Income Taxes 58,794 35,182
TOTAL OPERATING EXPENSES 491,761 436,936
OPERATING INCOME 98,870 83,716
NONOPERATING INCOME (LOSS) (3,811) 12,925
NONOPERATING EXPENSES 10,623 7,407
NONOPERATING INCOME TAX EXPENSE (CREDIT) (4,656) 3,722
INTEREST CHARGES 20,742 21,461
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 68,350 64,051
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 124,632 -
NET INCOME 192,982 64,051
PREFERRED STOCK DIVIDEND REQUIREMENTS 314 314
EARNINGS APPLICABLE TO COMMON STOCK $192,668 $ 63,737
The common stock of OPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $321,201 $462,483 $401,297 $ (196) $1,184,785
Common Stock Dividends (32,582) (32,582)
Preferred Stock Dividends (314) (314)
1,151,889
Comprehensive Income:
Other Comprehensive Income (Loss) (201) (201)
Net Income 64,051 64,051
Total Comprehensive Income 63,850
MARCH 31, 2002 $321,201 $462,483 $432,452 $ (397) $1,215,739
JANUARY 1, 2003 $321,201 $462,483 $522,316 $(72,886) $1,233,114
Common Stock Dividends (41,934) (41,934)
Preferred Stock Dividends (314) (314)
1,190,866
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (4,115) (4,115)
Net Income 192,982 192,982
Total Comprehensive Income 188,867
MARCH 31, 2003 $321,201 $462,483 $673,050 $(77,001) $1,379,733
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,135,098 $3,116,825
Transmission 907,021 905,829
Distribution 1,122,732 1,114,600
General 227,014 260,153
Construction Work in Progress 307,842 288,419
Total Electric Utility Plant 5,699,707 5,685,826
Accumulated Depreciation and Amortization 2,331,793 2,566,828
NET ELECTRIC UTILITY PLANT 3,367,914 3,118,998
OTHER PROPERTY AND INVESTMENTS 58,084 61,686
LONG-TERM RISK MANAGEMENT ASSETS 101,736 103,230
CURRENT ASSETS:
Cash and Cash Equivalents 32,412 5,285
Accounts Receivable:
Customers 112,495 95,100
Affiliated Companies 98,926 124,244
Miscellaneous 25,567 19,281
Allowance for Uncollectible Accounts (898) (909)
Fuel 75,920 87,409
Materials and Supplies 83,327 85,379
Risk Management Assets 114,581 92,108
Prepayments and Other 36,370 12,083
TOTAL CURRENT ASSETS 578,700 519,980
REGULATORY ASSETS 549,421 568,641
DEFERRED CHARGES AND OTHER ASSETS 126,564 84,497
TOTAL ASSETS $4,782,419 $4,457,032
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (77,001) (72,886)
Retained Earnings 673,050 522,316
Total Common Shareholder's Equity 1,379,733 1,233,114
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 1,175,676 917,649
TOTAL CAPITALIZATION 2,580,907 2,176,261
OTHER NONCURRENT LIABILITIES 237,011 227,689
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 89,665 89,665
Long-term Debt Due Within One Year - Affiliated Companies
60,000 60,000
Short-term Debt - Affiliated Companies - 275,000
Advances from Affiliates 239,328 129,979
Accounts Payable - General 139,007 170,563
Accounts Payable - Affiliated Companies 68,551 145,718
Customer Deposits 19,994 12,969
Taxes Accrued 165,222 111,778
Interest Accrued 24,644 18,809
Obligations Under Capital Leases 10,348 14,360
Risk Management Liabilities 93,511 61,839
Other 54,233 80,608
TOTAL CURRENT LIABILITIES 964,503 1,171,288
DEFERRED INCOME TAXES 875,344 794,387
DEFERRED INVESTMENT TAX CREDITS 17,986 18,748
LONG-TERM RISK MANAGEMENT LIABILITIES 62,313 39,702
DEFERRED CREDITS 44,355 28,957
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $4,782,419 $4,457,032
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $192,982 $ 64,051
Adjustments for Noncash Items:
Cumulative Effect of Accounting Changes (124,632) -
Depreciation and Amortization 61,551 62,621
Deferred Income Taxes (1,563) (4,649)
Deferred Property Taxes 14,878 14,717
Mark to Market of Risk Management Contracts 14,156 (16,055)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 1,626 (2,618)
Fuel, Materials and Supplies 13,541 (6,416)
Accrued Utility Revenues 4,429 (5,368)
Prepayments and Other (24,288) (11,822)
Accounts Payable (108,723) (75,824)
Customer Deposits 7,025 509
Taxes Accrued 53,444 21,498
Interest Accrued 5,835 7,171
Other Operating Assets (54,220) 1,388
Other Operating Liabilities (26,276) (8,819)
Net Cash Flows From Operating Activities 29,765 40,384
INVESTING ACTIVITIES:
Construction Expenditures (56,372) (66,312)
Proceeds from Sale of Property and Other 1,633 154
Net Cash Flows Used For Investing Activities (54,739) (66,158)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 -
Change in Advances to Affiliates (net) 109,349 89,173
Retirement of Long-term Debt (240,000) -
Changes in Short-term Debt (net) (275,000) -
Dividends Paid on Common Stock (41,934) (32,582)
Dividends Paid on Cumulative Preferred Stock (314) (314)
Net Cash Flows From Financing Activities 52,101 56,277
Net Increase in Cash and Cash Equivalents 27,127 30,503
Cash and Cash Equivalents at Beginning of Period 5,285 8,848
Cash and Cash Equivalents at End of Period $ 32,412 $ 39,351
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $14,551,000 and
$13,900,000 and for income taxes was $(22,475,000) and $(5,574,000) in 2003 and
2002, respectively. Noncash acquisitions under capital leases were $98,000 in
2002.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002
Public Service Company of Oklahoma (PSO) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electricity to
approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO
sells electric power to other utilities, municipalities and rural electric
cooperatives.
Wholesale power marketing activities are conducted on PSO's behalf by AEPSC.
PSO, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.
Results of Operations
In 2003, Net Income increased by $2.3 million primarily resulting from increased
wholesale margins and increased transmission revenues, partially offset by
higher Interest Charges.
Changes in Operating Revenues
Increase (Decrease)
(in millions) %
Electric Generation 85.8 92
Electric Transmission and Distribution
5.6 10
Sales to AEP Affiliates 2.3 110
Total Operating Revenues $93.7 63
Electric Generation revenues increased in 2003 as a result of increased fuel
related revenues and retained wholesale margins.
The increase in Electric Transmission & Distribution revenues is due to
increased transmission revenues, as distribution revenues were virtually flat.
Sales to AEP Affiliates increased primarily due to higher prices.
Changes in Operating Expenses
Increase (Decrease)
(in millions) %
Fuel for Electric Generation $45.1 78
Purchased Electricity for Resale
14.8 N.M.
Purchased Electricity from AEP Affiliates
25.2 150
Other Operation 5.0 19
Maintenance (4.8) (34)
Depreciation and Amortization 0.6 3
Taxes Other Than Income Taxes 1.8 23
Income Taxes (Credits) 1.2 74
Total Operating Expenses $88.9 63
N.M. = Not Meaningful
The increase in Fuel for Electric Generation in 2003 was primarily due to higher
market prices for natural gas and increased MWH generation.
The increase in purchased electricity expenses was due to higher prices offset
in part by reduced MWH purchases.
Other Operation expense increased in 2003 primarily due to increased customer
related expenses and a credit posted in 2002 related to a true-up of rents
received from affiliates.
Maintenance expense decreased in 2003 largely as a result of the absence of
expenses to repair damage to overhead lines caused by a winter storm in 2002.
Taxes Other Than Income Taxes increased in 2003 primarily due to an increase in
ad valorem taxes.
Income Taxes increased in 2003 primarily due to an increase in pre-tax income.
Other Changes
Interest Charges increased due to increases in average long-term debt balances
and higher average interest rates.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $179,149 $ 93,337
Electric Transmission and Distribution 59,118 53,555
Sales to AEP Affiliates 4,395 2,094
TOTAL OPERATING REVENUES 242,662 148,986
OPERATING EXPENSES:
Fuel for Electric Generation 103,174 58,097
Purchased Electricity for Resale 12,491 (2,344)
Purchased Electricity from AEP Affiliates 42,107 16,845
Other Operation 31,618 26,639
Maintenance 9,394 14,169
Depreciation and Amortization 21,494 20,916
Taxes Other Than Income Taxes 9,646 7,848
Income Taxes (Credits) (408) (1,594)
TOTAL OPERATING EXPENSES 229,516 140,576
OPERATING INCOME 13,146 8,410
NONOPERATING INCOME 650 106
NONOPERATING EXPENSES 439 595
NONOPERATING INCOME TAX CREDIT 200 141
INTEREST CHARGES 12,866 9,710
NET INCOME (LOSS) 691 (1,648)
LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 638 $ (1,701)
The common stock of PSO is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $157,230 $180,016 $142,994 $ - $480,240
Common Stock Dividends (22,455) (22,455)
Preferred Stock Dividends (53) (53)
457,732
Comprehensive Income (Loss):
Other Comprehensive Income - -
Net Income (Loss) (1,648) (1,648)
Total Comprehensive Income (Loss) (1,648)
MARCH 31, 2002 $157,230 $180,016 $118,838 $ - $456,084
JANUARY 1, 2003 $157,230 $180,016 $116,474 $(54,473) $399,247
Common Stock Dividends (7,500) (7,500)
Preferred Stock Dividends (53) (53)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
391,146
Comprehensive Income (Loss):
Other Comprehensive Income (Loss),
Net of Taxes:
Minimum Pension Liability (58) (58)
Unrealized Loss on Cash Flow
Power Hedges (1,197) (1,197)
Net Income 691 691
Total Comprehensive Income (Loss) (564)
MARCH 31, 2003 $157,230 $180,016 $109,064 $(55,728) $390,582
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,040,642 $1,040,520
Transmission 431,553 432,846
Distribution 991,688 990,947
General 200,630 206,747
Construction Work in Progress 95,186 88,444
Total Electric Utility Plant 2,759,699 2,759,504
Accumulated Depreciation and Amortization 1,241,480 1,239,855
NET ELECTRIC UTILITY PLANT 1,518,219 1,519,649
OTHER PROPERTY AND INVESTMENTS 4,931 5,383
LONG-TERM RISK MANAGEMENT ASSETS 7,484 4,481
CURRENT ASSETS:
Cash and Cash Equivalents 15,975 16,774
Accounts Receivable:
Customers 30,626 31,687
Affiliated Companies 15,939 14,139
Allowance for Uncollectible Accounts (54) (84)
Fuel Inventory 18,941 19,973
Materials and Supplies 38,178 37,375
Under-recovered Fuel Costs 77,701 76,470
Risk Management Assets 7,100 3,841
Prepayments and Other 3,643 2,735
TOTAL CURRENT ASSETS 208,049 202,910
REGULATORY ASSETS 25,417 26,150
DEFERRED CHARGES 45,755 18,117
TOTAL ASSETS $1,809,855 $1,776,690
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $ 157,230 $ 157,230
Paid-in Capital 180,016 180,016
Accumulated Other Comprehensive Income (Loss) (55,728) (54,473)
Retained Earnings 109,064 116,474
Total Common Shareholder's Equity 390,582 399,247
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 75,000
Long-term Debt 445,514 445,437
TOTAL CAPITALIZATION 916,363 924,951
OTHER NONCURRENT LIABILITIES 54,853 54,761
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 100,000 100,000
Advances from Affiliates 119,820 86,105
Accounts Payable - General 74,807 61,169
Accounts Payable - Affiliated Companies 59,616 78,076
Customer Deposits 23,863 21,789
Taxes Accrued 22,732 6,854
Interest Accrued 9,384 6,979
Risk Management Liabilities 6,658 3,260
Other 15,210 24,957
TOTAL CURRENT LIABILITIES 432,090 389,189
DEFERRED INCOME TAXES 342,529 341,396
DEFERRED INVESTMENT TAX CREDITS 31,754 32,201
REGULATORY LIABILITIES AND DEFERRED CREDITS 27,392 32,611
LONG-TERM RISK MANAGEMENT LIABILITIES 4,874 1,581
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $1,809,855 $1,776,690
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ 691 $ (1,648)
Adjustments to Reconcile Net Income (Loss) to Net Cash
Flows Used For Operating Activities:
Depreciation and Amortization 21,494 20,916
Deferred Income Taxes 1,309 1,886
Deferred Investment Tax Credits (447) (448)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (769) (3,733)
Fuel, Materials and Supplies 229 (1,346)
Accounts Payable (4,822) (31,427)
Taxes Accrued 15,878 9,407
Deferred Property Taxes (24,413) (21,210)
Fuel Recovery (1,231) 2,380
Changes in Other Assets (11,662) (7,606)
Changes in Other Liabilities (5,606) 4,032
Net Cash Flows Used For Operating Activities (9,349) (28,797)
INVESTING ACTIVITIES:
Construction Expenditures (17,612) (10,559)
Net Cash Flows Used For Investing Activities (17,612) (10,559)
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 33,715 63,910
Dividends Paid on Common Stock (7,500) (22,455)
Dividends Paid on Cumulative Preferred Stock (53) (53)
Net Cash Flows From Financing Activities 26,162 41,402
Net Increase (Decrease) in Cash and Cash Equivalents (799) 2,046
Cash and Cash Equivalents at Beginning of Period 16,774 5,795
Cash and Cash Equivalents at End of Period $ 15,975 $ 7,841
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,653,000 and
$5,157,000 and for income taxes was $(959,000) and $1,783,000 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.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERNAMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSISSUBSIDIARY COMPANIES
SCHEDULE OF RESULTS OF OPERATIONS
FIRST QUARTERCONSOLIDATED LONG-TERM DEBT
September 30, 2003 vs. FIRST QUARTERand December 31, 2002
Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 437,000 retail customers in northeastern Texas, northwestern
Louisiana and western Arkansas. SWEPCo sells electric power to other utilities,
municipalities and rural electric cooperatives.
Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC.
SWEPCo, along with the other AEP electric operating subsidiaries, shares in
AEP's electric power transactions with other utility systems and power
marketers.
Results of Operations
Net Income increased $10.8 million or 133% for the quarter. The increase
resulted primarily from the cumulative effect of accounting changes due to the
adoption of SFAS 143.
Changes in Operating Revenues
Increase (Decrease)(Unaudited)
2003 2002
---- ----
(in millions)
%
Electric Generation $24.9 19
Electric Transmission and Distribution
(1.3) (2)
SalesTOTAL 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 AEP Affiliates 9.4 41
Total Operating Revenues $33.0 15
Electric Generation revenues increased in 2003 dueCaddis 527 -
Notes Payable to higher
wholesale revenues, a slight increase in customers, coupled with a more
profitable mix of sales in higher rate categories.
Sales to AEP Affiliates increased primarily due to higher prices.
Changes in Operating Expenses
Increase
(Decrease)
(in
millions) %
Fuel for Electric Generation $14.1 16
Purchased Electricity for Resale 8.5 209
Purchased Electricity from AEP Affiliates
5.3 97Trust 321 -
Other Operation (1.3) (3)
Maintenance 1.0 8
Depreciation and Amortization (2.1) (7)
Taxes Other Than Income Taxes 1.4 10
Income Taxes 2.5 91
Total Operating Expenses $29.4 15
Fuel for Electric Generation increased in 2003 due to both increased generation
and higher fuel costs.
In 2003, Purchased Electricity increased overall due to higher costs for
purchased power offset in part by reduced MWHs purchased.
Maintenance expense increased in 2003 as a result of scheduled maintenance at
several power plants.
The decrease in Depreciation and Amortization expense was due primarily to the
restoration of a regulatory asset for recovery of a fuel related cost allowed in
a fuel proceeding for the Arkansas portion of SWEPCo's operations.
In 2003, Taxes Other Than Income Taxes increased due to increased payroll and
state gross receipts taxes.
Income Taxes attributable to operations increased in 2003 due to increased
pre-tax income.
Other Changes
Nonoperating Income increased in 2003 due primarily to increased interest income
and AFUDC.
In 2003, Interest Charges increased due to increased levels of debt outstanding
and higher average interest rates.
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
Notes 2 and 3).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
======== =======
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:
Electric Generation $156,681 $131,761
Electric Transmission and Distribution 66,242 67,539
Sales to AEP Affiliates 32,355 22,959
TOTAL OPERATING REVENUES 255,278 222,259
OPERATING EXPENSES:
Fuel for Electric Generation 103,010 88,883
Purchased Electricity for Resale 12,567 4,070
Purchased Electricity from AEP Affiliates 10,810 5,485
Other Operation 40,857 42,151
Maintenance 12,817 11,838
Depreciation and Amortization 28,035 30,140
Taxes Other Than Income Taxes 15,873 14,466
Income Taxes 5,265 2,757
TOTAL OPERATING EXPENSES 229,234 199,790
OPERATING INCOME 26,044 22,469
NONOPERATING INCOME 872 102
NONOPERATING EXPENSES 521 566
NONOPERATING INCOME TAX EXPENSE 50 28
INTEREST CHARGES 15,854 13,818
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 10,491 8,159
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 8,517 -
NET INCOME 19,008 8,159
PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57
EARNINGS APPLICABLE TO COMMON STOCK $ 18,951 $ 8,102
The common stock of SWEPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)
Accumulated Other
Comprehensive
Common Paid-in Retained Income (Loss)
Stock Capital Earnings Total
(in thousands)
JANUARY 1, 2002 $135,660 $245,003 $308,915 $ - $689,578
Common Stock Dividends (18,964) (18,964)
Preferred Stock Dividends (57) (57)
670,557
Comprehensive Income:
Other Comprehensive Income - -
Net Income 8,159 8,159
Total Comprehensive Income 8,159
MARCH 31, 2002 $135,660 $245,003 $298,053 $ - $678,716
JANUARY 1, 2003 $135,660 $245,003 $334,789 $(53,683) $661,769
Common Stock Dividends (18,199) (18,199)
Preferred Stock Dividends (57) (57)
643,513
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (1,367) (1,367)
Net Income 19,008 19,008
Total Comprehensive Income 17,641
MARCH 31, 2003 $135,660 $245,003 $335,541 $(55,050) $661,154
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,503,521 $1,503,722
Transmission 575,856 575,003
Distribution 1,040,007 1,063,564
General 402,229 378,130
Construction Work in Progress 85,836 75,755
Total Electric Utility Plant 3,607,449 3,596,174
Accumulated Depreciation and Amortization 1,702,196 1,697,338
NET ELECTRIC UTILITY PLANT 1,905,253 1,898,836
OTHER PROPERTY AND INVESTMENTS 5,793 5,978
LONG-TERM RISK MANAGEMENT ASSETS 8,549 5,119
CURRENT ASSETS:
Cash and Cash Equivalents 7,163 2,069
Accounts Receivable:
Customers 62,237 62,359
Affiliated Companies 20,651 19,253
Allowance for Uncollectible Accounts (2,116) (2,128)
Fuel Inventory 58,814 61,741
Materials and Supplies 33,806 33,539
Under-recovered Fuel Costs - 2,865
Risk Management Assets 8,110 4,388
Prepayments and Other 18,565 17,851
TOTAL CURRENT ASSETS 207,230 201,937
REGULATORY ASSETS 52,645 49,233
DEFERRED CHARGES 74,034 47,572
TOTAL ASSETS $2,253,504 $2,208,675
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $ 135,660 $ 135,660
Paid-in Capital 245,003 245,003
Accumulated Other Comprehensive Income (Loss) (55,050) (53,683)
Retained Earnings 335,541 334,789
Total Common Shareholder's Equity 661,154 661,769
Preferred Stock 4,700 4,701
SWEPCo-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of SWEPCo 110,000 110,000
Long-term Debt 637,496 637,853
TOTAL CAPITALIZATION 1,413,350 1,414,323
OTHER NONCURRENT LIABILITIES 80,142 78,494
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 595 55,595
Advances from Affiliates, net 103,123 23,239
Accounts Payable - General 56,856 62,139
Accounts Payable - Affiliated Companies 46,762 58,773
Customer Deposits 22,220 20,110
Taxes Accrued 60,263 19,081
Interest Accrued 12,367 17,051
Risk Management Liabilities 7,606 3,724
Over-recovered Fuel 17,090 17,226
Other 19,781 34,565
TOTAL CURRENT LIABILITIES 346,663 311,503
DEFERRED INCOME TAXES 341,398 341,064
DEFERRED INVESTMENT TAX CREDITS 43,109 44,190
REGULATORY LIABILITIES AND DEFERRED CREDITS 23,274 17,295
LONG-TERM RISK MANAGEMENT LIABILITIES 5,568 1,806
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES $2,253,504 $2,208,675
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:
Net Income $19,008 $8,159
Adjustments to Reconcile Net Income to
Net Cash Flows From Operating Activities:
Depreciation and Amortization 28,035 30,140
Deferred Income Taxes (4,034) (3,930)
Deferred Investment Tax Credits (1,081) (1,131)
Cumulative Effect of Accounting Changes (8,517) -
Mark-to-Market of Risk Management Contracts (1,462) 7,695
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (1,288) (9,762)
Fuel, Materials and Supplies 2,660 (18,504)
Accounts Payable (17,294) (2,646)
Taxes Accrued 41,182 27,254
Deferred Property Taxes (27,945) (27,217)
Fuel Recovery 2,729 10,391
Change in Other Assets 1,461 9,511
Change in Other Liabilities (9,120) (7,260)
Net Cash Flows From Operating Activities 24,334 22,700
INVESTING ACTIVITIES:
Construction Expenditures (25,702) (11,715)
Proceeds from Sale of Assets and Other 284 -
Net Cash Flows Used For Investing Activities (25,418) (11,715)
FINANCING ACTIVITIES:
Retirement of Long-term Debt (55,450) (150,450)
Change in Advances from Affiliates (net) 79,884 154,959
Dividends Paid on Common Stock (18,199) (18,964)
Dividends Paid on Cumulative Preferred Stock (57) (57)
Net Cash Flows From (Used For) Financing Activities 6,178 (14,512)
Net Increase (Decrease) in Cash and Cash Equivalents 5,094 (3,527)
Cash and Cash Equivalents at Beginning of Period 2,069 5,415
Cash and Cash Equivalents at End of Period $ 7,163 $ 1,888
Supplemental Disclosure:
Cash (received) paid for interest net of capitalized amounts was $17,963,000 and
$10,203,000 and for income taxes was ($755,000) and $8,581,000 in 2003 and 2002,
respectively.
See Notes to Financial Statements beginning on page L-1.
COMBINED NOTES TO FINANCIAL STATEMENTS
MARCH 31, 2003
(UNAUDITED)
The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list indicates the registrants
to which the footnotes apply:
1. General AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2. Significant
Accounting
Policies and New
Accounting
Pronouncements AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3. Extraordinary Items and
Cumulative Effect AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4. Goodwill and
Other Intangible Assets AEP, SWEPCo
5. Rate Matters AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6. Customer Choice
and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
7. Commitments and
Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
8. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO,
9. Sustained Earnings
Improvement
Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10. Dispositions,
Discontinued
Operations and
Assets Held for Sale AEP, APCo, CSPCo, I&M, KPCo, OPCo
11. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
12. Leases AEP, OPCo
13. Minority Interest
in Finance Subsidiary AEP
14. Financing and Related
Activities AEP, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
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.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".39." Such reclassifications had no effect
ofon 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.operations (see Note 30 in the Current Report on Form 8-K dated May 14,
2003). As a result, in the first quarter of 2002 Gas PipelineOperations revenues increased by $41 million and
Storage revenues
decreased by $47$8 million Investments revenueand UK Operations and Other revenues increased
by $2 million and decreased by $10$11 million for the three and nine month
periods ended September 30, 2002, respectively. Fuel for Electric
Generation decreased by $27$16 million and $60 million and Purchased Gas
for Resale decreased by $58 million.$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 $21$105 million and $235
million and Taxes Other Than Income Taxes increased by $7 million.$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
AND NEW ACCOUNTING PRONOUNCEMENTS
Significant Accounting Policies
Components of-------------------------------
Accumulated Other Comprehensive Income
(Loss) - Other
comprehensive income (loss) is included on the balance sheet in the
equity section. The following table provides the components that
comprise the balance sheet amount in Accumulated Other Comprehensive
Income (Loss) for AEP:
March 31, December 31,
2003 2002
Components (in millions)
Foreign Currency Translation Adjustments $ 17 $ 4
Unrealized Losses on Securities (1) (2)
Unrealized Losses on Cash Flow Hedges (38) (16)
Minimum Pension Liability (580) (595)
$(602) $(609)
Accumulated Other Comprehensive Income (Loss) for AEP registrant
subsidiaries as of March 31, 2003, and December 31, 2002 is shown in the
following table.
March 31, December 31,
2003 2002
Components (in thousands)
Unrealized Losses
on Cash Flow Hedges:
APCo $ (14,438) $ (1,920)
CSPCo (7,610) (267)
I&M (8,143) (286)
KPCo (2,543) 322
OPCo (10,477) (738)
PSO (1,239) (42)
SWEPCo (1,415) (48)
TCC (1,054) (36)
TNC (436) (15)
Non-Registrants 9,220 (13,368)
$ (38,135) $(16,398)
Minimum Pension Liability:
APCo $(70,162) $(70,162)
CSPCo (59,090) (59,090)
I&M (40,201) (40,201)
KPCo (9,773) (9,773)
OPCo (66,524) (72,148)
PSO (54,489) (54,431)
SWEPCo (53,635) (53,635)
TCC (73,124) (73,124)
TNC (30,755) (30,748)
Non-Registrants (121,879) (131,898)
$(579,632) $(595,210)
The following tables represent the activity in Other Comprehensive
Income (Loss) related to the effect of adopting SFAS 133 for derivative
contracts that qualify as cash flow hedges at March 31, 2003:
Domestic Domestic Foreign AEP
Power Gas Currency Interest Rate Consolidated
(in millions)
Accumulated OCI, December 31, 2002 $ (1) $ - $(3) $(12) $(16)
Changes in Fair Value (a) (65) 8 5 6 (46)
Reclassifications from OCI to Net
Income (b) 23 - - 1 24
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(43) $ 8 $ 2 $ (5) $(38)
APCo Domestic Foreign APCo
Power Currency Interest Rate Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920)
Changes in Fair Value (a) (19,201) - (104) (19,305)
Reclassifications from OCI to Net
Income (b) 6,649 2 136 6,787
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(12,946) $(188) $(1,304) $(14,438)
CSPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (267)
Changes in Fair Value (a) (11,251)
Reclassifications from OCIWe expect to Net
Income (b) 3,908
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(7,610)
I&M Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (286)
Changes in Fair Value (a) (12,039)
Reclassifications from OCI to Net
Income (b) 4,182
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(8,143)
KPCo Domestic KPCo
Power Interest Rate Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (103) $425 $ 322
Changes in Fair Value (a) (4,357) (43) (4,400)
Reclassifications from OCI to Net
Income (b) 1,513 22 1,535
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(2,947) $404 $(2,543)
OPCo Domestic Foreign OPCo
Power Currency Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738)
Changes in Fair Value (a) (14,928) - (14,928)
Reclassifications from OCI to Net
Income (b) 5,186 3 5,189
Accumulate OCI Derivative Gain (Loss)
March 31, 2003 (c) $(10,096) $(381) $(10,477)
PSO Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (42)
Changes in Fair Value (a) (1,833)
Reclassifications from OCI to Net
Income (b) 636
Accumulated OCI Derivative Gain (Loss) March
31, 2003 (c) $(1,239)
SWEPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (48)
Changes in Fair Value (a) (2,094)
Reclassifications from OCI to Net
Income (b) 727
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(1,415)
TCC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (36)
Changes in Fair Value (a) (1,559)
Reclassifications from OCI to Net
Income (b) 541
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(1,054)
TNC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (15)
Changes in Fair Value (a) (645)
Reclassifications from OCI to Net
Income (b) 224
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $ (436)
(a) Changes in fair value - Changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of
related income taxes.
(b) 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.
(c) Accumulated OCI Derivative Gain (Loss) March 31, 2003 - 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.
Approximately $31reclassify approximately $96 million of net losses from
cash flow hedges in Accumulated Other Comprehensive Income (Loss) at
March 31,September 30, 2003 are
expected to be reclassified to net income induring the next twelve months asat the
items beingtime the hedged settle.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 reclassifiedthat 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 market price changes. The maximum term for which the exposureour requirement to consolidate, and there is no
change in net income due to the variabilityconsolidation of future cash flowsSabine.
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 being hedgedno cumulative effect of an accounting
change recorded as a result of our requirement to consolidate JMG, and
there is five years.
Common Stock Options and Restricted Shares - AEP has two stock-based
employee compensation plans with outstanding stock options. AEP accounts
for these plans under the recognition and measurement principles of APB
Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and
related Interpretations. No stock-based employee compensation expense is
reflectedno change in AEP's earnings, as all options granted under these plans
had exercise prices equal to or above the market value of the underlying
common stock on the date of grant.
AEP awarded 102,513 restricted stock units to certain AEP employees in
March 2003. The units vest in equal one-third increments in January
2004, 2005 and 2006. At each vesting date, shares will be issued at no
costnet income due to the employee. In accordance with APB 25, the compensation
expenseconsolidation of approximately $2.3 million will be expensed over the vesting
period of the units. The value of the units was based on a $21.95 per
share value at the grant date. The amount of compensation expense
recognized during the first quarter of 2003 in AEP's Consolidated
Statements of Operations was $463 thousand, pre-tax.
The following table illustrates the effect on AEP's Net Income (Loss)
and earnings (loss) per share as if AEP had applied the fair value
recognition provisions of FASB Statement No. 123,JMG. See
Note 10 "Leases" for further disclosures.
SFAS 143 "Accounting for Stock-Based Compensation", to stock-based employee compensation awards:
Three Months Ended
March 31,
2003 2002
(in millions, except per share data)
Net Income (loss), as reported $ 440 $(169)
Add: Stock-based compensation expense included in
reported net income, net of related tax effects - (a) -
Deduct: Stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects (1) (2)
Pro Forma Net Income (Loss) $ 439 $ (171)
Earnings (Loss) per Share:
Basic - as Reported $1.24 $(0.52)
Basic - Pro Forma 1.23 (0.53)
Diluted - as Reported $1.24 $(0.52)
Diluted - Pro Forma 1.23 (0.53)
(a) Compensation expense related to restricted units during the first
quarter of 2003 was $301 thousand, net of tax.
New Accounting Pronouncements
AEPAsset Retirement Obligations"
We implemented SFAS 143, "Accounting for Asset Retirement Obligations",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 thatcost. These costs had previously been recorded for
generation that doesand did not qualify as a legal obligation which wasalthough these
costs were collected in depreciation rates by certain formerly regulated
subsidiaries.
AEP hasWe completed a review of itsour asset retirement obligations and concluded
that at present, it haswe have related legal liabilities for nuclear decommissioning costs
for itsour Cook Plant and itsour 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 AEPwe
presently recovers itsrecover our nuclear decommissioning costs in itsour regulated
cash flow and thus hadhave existing balances recorded for such nuclear
retirement obligations, itwe recognized the cumulative difference inbetween
the amount already provided through rates versusand the new
methodology ofamount 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 AEP'sour regulated operations. AEPIn
the first quarter of 2003, we recorded an unfavorable cumulative effect
of $45.4 million after tax for theour non-regulated operations ($38.0
million related to Ash Ponds and
$7.4in 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 and Coal Operations)in the Investments - Other
segment).
Certain of AEP'sour operating companies have recorded, in Accumulated
Depreciation and Amortization, removal costs collected from rate payersratepayers
for certain assets that do not have associated legal asset retirement
obligations. To the extent that such operating companies have now been
deregulated AEPwe reversed the balance of such removal costs, totaling
$287.2 million after tax, from accumulated depreciation which resulted
in a net favorable cumulative effect.effect in the first quarter of 2003.
However, AEPwe did not adjust the balance of such removal costs for itsour
regulated operations, and in accordance with the present method of
recovery, will continue to record such amounts through depreciation
expense and accumulated depreciation. AEP estimatesWe estimate that it haswe have
approximately $1.2 billion of such regulatory liabilities recorded in
Accumulated Depreciation and Amortization as of both March 31,September 30, 2003
and December 31, 2002.
The following is a summary by registrant of the regulatory liabilities
for removal costs included in Accumulated Depreciation and Amortization:
March 31, 2003 December 31,2002
(in millions)
AEGCo $ 28.4 $ 28.0
APCo 94.5 94.6
CSPCo 96.7 96.0
I&M 252.7 250.5
KPCo 21.9 23.7
OPCo 96.2 97.0
PSO 198.9 202.6
SWEPCo 220.7 219.5
TCC 97.7 97.5
TNC 74.7 75.0
Non-Registrants 0.5 0.5
$1,182.9 $1,184.9
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)
UK$(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
The following is a summary by registrant of the cumulative effect of
changes in accounting principles:
Pre-tax Income (Loss) After-tax Income(Loss)
U. K. Plants, U. K. Plants,
Wind Mills Reversal of Wind Mills Reversal of
and Coal Cost of and Coal Cost of Removal
Ash Ponds Operations Removal Ash Ponds Operations
(in millions)
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
SWEPCo - - 13.0 - - 8.4
TCC - - - - - -
TNC - - 4.7 - - 3.1
Other - (11.3) 1.2 - (7.4) 0.8
$(62.8) $(11.3) $ 472.6 $(38.0) $(7.4) $287.2
AEP has$398.5 $241.8
======== =======
We have identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution and gas
distributionpipeline assets, as a result of certain easements on property on which
AEP haswe have assets. Generally, such easements are perpetual and require only
the retirement and removal of AEP'sour assets upon the cessation of the
property's use. The retirement obligation is not estimable for such
easements since AEP planswe plan to use its propertiesour facilities indefinitely. The
retirement obligation would only be recognized if and when AEP abandonswe abandon or
ceasescease the use of specific easements.
The following is a reconciliation of the beginning and ending aggregate
carrying amount of asset retirement obligations (in millions):
The following is a reconciliation of the beginning and ending aggregate
carrying amount of asset retirement obligations:
U.K.
Plants,
Wind
Mills
Nuclear Ash and Coal
Decommissioning Ponds Operations Total
(in millions)--------------- ----- ---------- -----
Asset Retirement Obligation
Liability at
January 1, 2003 $718.3 $69.8 $37.2 $825.3
Accretion expense 12.7 1.4 0.4 14.539.1 4.2 1.6 44.9
Liabilities incurred - - 8.3 8.3
Foreign currency
translation - - 3.5 3.5
------- ------ ------ -------
Asset Retirement Obligation
Liability at
March 31,September 30, 2003 $731.0 $71.2 $37.6 $839.8
The following is a reconciliation of beginning and ending aggregate
carrying amounts of asset retirement obligations by registrant following
the adoption of SFAS 143:
Balance At Balance at
January 1, 2003 Accretion March 31, 2003
(in millions)
AEGCo (a) $ 1.1 $ - $ 1.1
APCo (a) 20.1 0.4 20.5
CSPCo (a) 8.1 0.2
I&M (b) 516.1 9.0 525.1
OPCo (a) 39.5 0.8 40.3
TCC (c) 203.2 3.8 207.0
Other (d) 37.2 0.3 37.5
$825.3 $14.5 $839.8
(a) Consists of asset retirement obligations related to ash ponds.
(b) Consists of asset retirement obligations related to ash ponds ($1.1
million at March 31, 2003) and nuclear decommissioning costs for the Cook
Plant ($524 million at March 31, 2003). (c) Consists of asset retirement
obligations related to nuclear decommissioning costs for STP. (d)
Consists of asset retirement obligations related to wind farms, the U.K.
plants and certain coal mining facilities.$757.4 $74.0 $50.6 $882.0
======= ====== ====== =======
Accretion expense is included in Maintenance and Other Operation expense
in AEP'sour accompanying Consolidated Statements of Operations and in Other
Operation expense in the Income Statements of the other individual
registrants.Operations.
As of March 31,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 $706$800 million and $716 million,
respectively, recorded in Other Assets on AEP'sour Consolidated Balance
Sheets.
Pro forma net income and earnings per share haveare not been presented for the
quarter ended March 31,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 forduring those periods.
The following is a summary by registrant 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 $ 1.0 $ 1.0
APCo 20.2 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 - -
Non-Registrants 37.2 35.3
$825.3 $769.2
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 "Recognition and
Reporting of Gains and Losses on Energy Contracts under Issue
No.rescinds EITF 98-10 and
00-17" (EITF 02-3). See Note 3.
FASB Stock-based Compensation Project
In March 2003,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 FASB added a project to address issues related to
share-based payments. In April 2003, the FASB decided that goods and
services, including employee stock options, received in exchange for
stock-based compensation should be recognized in the income statement as
an expense, with the cost measuredrecognition of physical inventories at fair value. An exposure draft is
expectedvalue
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 endeffects of this yearimplementation 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 a final statement could be
effective$15
million in 2004.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 derivative instruments, including
certain derivative instruments embedded in other contracts and for
hedging activities.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 effectivethe 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 AEP for contracts entered intocash or modified after June 30, 2003. AEPother
assets and its subsidiaries are evaluating(3) obligations that can be settled with shares, the impactmonetary
value of adoptingwhich is either (a) fixed, (b) tied to the requirementsvalue 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 149.
3. EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT150,
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 EffectPreferred Stocks of Accounting Changes -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 AEP'sour 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 143, "Accounting5, 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 Asset Retirement Obligations", (see Note 2) isguarantees issued or modified after December
31, 2002. The disclosure requirements of FIN 45 are effective for
AEP on January 1, 2003. SFAS 143 generally applies to
legal obligations associated with the retirementfinancial statements of long-lived assets. A
company is required to recognize an estimated liability for any legal
obligations associated with the future retirement of its long-lived
assets. The liability is measured at fair value and is capitalized as
part of the related asset's capitalized cost. The increase in the
capitalized cost is included in determining depreciation expense over
the expected useful life of the asset. The catch-up effect of adopting
SFAS 143 will be recorded as a cumulative effect of an accounting
change. Additionally, because the asset retirement obligation is
recorded initially at fair value, accretion expense (similar to
interest) will be recognized each period as an operating expense in the
statement of operations. AEP has recorded $242 million in after tax
income related to the recording of Asset Retirement Obligations in AEP's
Consolidated Statements of Operations as a cumulative effect of
accounting change.
EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under
EITF 02-3, mark-to-market accounting is precluded for energy trading
contracts that are not derivatives pursuant to SFAS 133. The consensus
to rescind EITF 98-10 will also eliminate any basis for recognizing
physical inventories at fair value other than as provided by GAAP. The
consensus to rescind EITF 98-10 is effective for all new contracts
entered into (and physical inventory purchased) after October 25, 2002.
The consensus is effective for fiscalinterim or annual periods beginningending after December
15, 2002,2002. See Note 7 for further disclosures.
Future Accounting Changes
FASB's standard-setting process is ongoing. Until new standards have
been finalized and applies to all energy trading contractsissued by FASB, we cannot determine the impact on the
reporting of our operations that existed on or
before October 25, 2002 that remain in effect as of the date of
implementation, January 1, 2003. Effective January 2003, nonderivative
energy contracts entered into prior to October 25, 2002 are required to
be accounted for on a settlement basis and inventory is required to be
presented at the lower of cost or market. The effect of implementing
this consensus is reported as a cumulative effect of an accounting
change. Such contracts and inventory are accounted for at fair value
through December 31, 2002. Energy contracts that qualify as derivatives
were accounted for at fair value under SFAS 133. AEP has recorded a $49
million after tax charge against net income as Accounting for Risk
Management Contracts in AEP's Consolidated Statements of Operations in
Cumulative Effect of Accounting Changes. This amount will be recognized
when the positions settle.
See table below for details of the Cumulative Effect of Accounting
Changes.
Three Months Ended March 31,
Description 2003 2002
(in millions)
Accounting for Risk Management Contracts (EITF 02-3) $(49) $ -
Asset Retirement Obligations (SFAS 143) 242 -
Goodwill and Other
Intangible Assets - (350)
Total $193 $(350)
The following is a summary by registrant of the cumulative effect of
changes in accounting principles for the adoptions of SFAS 143 and EITF
02-3:
SFAS 143 Cumulative Effect EITF 02-3 Cumulative Effect
Pre-tax After-tax After-tax
Income Income Income
(Loss) (Loss) Pre-tax (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 - -
Other (10.1) (6.6) (49.5) (37.3)
$398.5 $241.8 $(67.7) $(49.1)
may result from any such future
changes.
4. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
The changes in the carrying amount of goodwill for the three months
ended March 31, 2003 by operating segment are:
Investments
Utility Gas U.K. AEP
Operations Operations Operations Other Consolidated
(in millions)
Balance January 1, 2003 $37.1 $306.3 $11.1 $41.5 $396.0
Foreign currency
exchange rate changes - - (0.3) - (0.3)
Balance March 31, 2003 $37.1 $306.3 $10.8 $41.5 $395.7
Acquired Intangible Assets
The gross carrying amount, accumulated amortization and amortization
life by major asset class are shown in the following table:
March 31, 2003 December 31, 2002
Gross Carrying Gross
Amortization Amount Accumulated Carrying Accumulated
Life Amortization Amount Amortization
(in millions)
Software and customer list
2 $ 0.5 $0.3 $ 0.5 $0.2
Software acquired 3 0.4 - 0.5 -
Patent 5 0.1 - 0.1 -
administration of contracts
7 2.4 0.6 2.4 0.6
Purchased technology 10 10.3 1.3 10.3 1.0
Advanced royalties 10 29.4 5.4 29.4 4.7
Total $43.1 $7.6 $43.2 $6.5
Amortization of intangible assets was $1.2 million ($1.1 million net of
foreign currency translation) and $1.0 million (no foreign currency
translation) for the three months ended March 31, 2003 and March 31,
2002.
Estimated aggregate amortization expense is $4.4 million for each year
2004 through 2006, $4.3 million in 2007, $4.1 million in 2008 and $4.0
million in 2009.
Fluctuations in the gross carrying values since December 31, 2002
represent changes in the foreign currency exchange rate.
Intangible assets subject to amortization are recorded in Other Assets in
the AEP Consolidated Balance Sheets.
5. RATE MATTERS
------------
Fuel in SPP - Affecting AEP, SWEPCo and TNCArea 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 approved a stipulationordered that delays competition would not begin in the SPP areas
of Texas until no sooner thanbefore January 1, 2007. All of SWEPCo's
Texas service territory and a small portion of TNC's service territory
are in the SPP. SWEPCo's existing Texas fuel cost recovery procedures
will continue until competition begins. SWEPCo will continue to set fuel
factors and determine final fuel costs in fuel reconciliation proceedings
during the SPP delay period. The PUCT has ruled that TNC fuel factors in the
SPP area will be based upon the price-to-beat fuel factors offered by
the retail electric provider (REP)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, should be used to reconcilefor
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 AEP and TNC
In June 2002, TNC filed with the PUCT to reconcile fuel costs and to
defer any unrecovered portion applicable to retail sales within its
ERCOT service area for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 2000 through December 2001 will be
the final fuel reconciliation for TNC's ERCOT service territory. At
December 31, 2001, the under-recovery balance associated with TNC's
ERCOT service area was $27.5 million including interest. During the
reconciliation period, TNC incurred $293.7 million of eligible fuel
costs serving both ERCOT and SPP retail customers. TNC also requested
authority to surcharge its SPP customers.customers for under-recovered fuel costs.
TNC's SPP customers will continue to be subject to fuel reconciliations
until competition begins in SPP.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 recommendsincludes 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 PFD's recommendations.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 scheduled to considerproposing that the
PFDsharing 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 May 22,July 15, 2003 addressing
the remand issues. Intervenors and the PUCT Staff filed statements of
position or testimony in August 2003 and is expectedTNC 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 issue a final orderthe requirements of the
AEP/CSW merger settlement to share off-system sales margins were
stricken by mid 2003. Any further adverse ruling fromthe ALJ. The ALJ ruled that the requirement to share
off-system sales margins had been determined by the PUCT couldand 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 a materialan 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 AEP and TCC
In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
defer its over-recovery of fuel for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 1998 through
December 2001 will be theTCC'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 withand hearings scheduledwere 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. A final order is expectedBased
upon the PUCT's remand of certain TNC issues, TCC established an
additional reserve of $9 million in latethe second quarter of 2003. An adverse ruling fromIn July
2003, the PUCTALJ requested that additional information be provided in excessthe
TCC fuel reconciliation related to the impact of the reserveTNC 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 65 "Customer Choice and Industry Restructuring"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 - Affecting AEP and 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 will bewas
filed at FERC in June 2003 regarding the fuel complaint.complaint and new
contracts. Management is unable to predict whether FERC will approve
this offer of settlement, whichbut 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. TheTNC
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 this estimatethe
provision and may have a negative impact on future results of
operations, cash flowflows and financial condition.
Environmental Surcharge Filing - Affecting AEP and 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 7.6.
In March 2003, the KPSC granted approximately $18 million of the
request. RateAnnual rate relief of $1.7 million annually will bewas effective in May 2003. In
July 2003
and an additional annual rate relief of $16.2 million will become
effective.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 AEP and PSO
In February 2003, the Director of the OCC filed an application requiring
PSO to file all documents necessary for a general rate review before
August 1, 2003.2003 (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.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 - Affecting AEP and AEP East and
AEP West companies
In September 2002, the FERC voted to hold hearings to consider requests
from certain wholesale customers located in Nevada and Washington to
break long-term contracts which they allege are "high-priced"."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
assigned to the case indicated that the parties' settlement efforts were not
progressing and he recommended that the complaint be placed back on the
schedule for a hearing. In February 2003, AEP and one of 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, AEPwe 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. The ALJ's order is preliminary and is subject to review by the
FERC. At a hearing held in April 2003, the utilities asked FERC
to void the long-term contracts. TheIn June 2003, the FERC will likely rule onissued an order
affirming the ALJ's order in
2003.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
these proceedingsthis proceeding or theirits impact on future results of operations.
6.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 - Affecting AEP, 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 complaintantscomplainants 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".elsewhere." Management is currently unable to predict the
timing of the AEP'sAEP 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-requiredstatutorily 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
- Affecting AEP, SWEPCo, TCC and TNC
As discussed in the 2002 Annual Report, onOn 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, certain environmental costs,unrefunded
accumulated excess earnings, excess of price-to-beat revenues over
market prices subject to certain conditions and limitations (Retail
clawback), and the difference between the pricea true-up of power obtained
through the legislatively-mandated capacity auctions and the power costs used in the PUCT's ECOM model
for 2002 and 2003 (Wholesale clawback)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 costsgeneration assets in the final 2004 true-up proceeding
including the sale or exchange of generation assets, stock valuation
methods or the use of an ECOM model. Onlymodel for nuclear generation assets. TCC
is the only AEP subsidiary that has stranded costs under the Texas
Legislation.
In latethe fourth quarter of 2002, TCC decided to obtain adetermine 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 andproceeding.
In December 2002, TCC filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. Such
sales would quantify the actual stranded costs. The
amount of stranded costs under this market valuation methodology will
be the amount by which netthe 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 biddingclosing process for the plants sold is not
expected to be completed before mid-2004, TCC requested that theits 2004
true-up proceeding be scheduled after completion of the divestiture of
theits 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 stranded costs
valuation in a rulemaking proceeding. The PUCT approved a rule,
in May 2003, thatwhich allows the market value obtained by selling nuclear
assets to be used in determining stranded costs. Since theThe PUCT also dismissed
theTCC's request to certify theits proposed divestiture plan, theplan; therefore its
divestiture plan utilized by TCC will still be subject to a prudency review in the 2004 true-up
proceedings.proceeding. The PUCT also initiatedadopted a rulemakingrule regarding the timing of the 2004
true-up proceedings scheduling TNC's filing in May 2004 and TCC's
filing in September 2004.2004 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 and liquidity.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 stranded costwholesale capacity
auction true-up adjustment for TCC for the 2004 true-up proceeding.
The decision to determine stranded costs using market prices,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
estimates,negative stranded cost estimate, enabled TCC to record in 2002 a $262
million regulatory asset and related revenues which represents the
quantifiable amount of stranded coststhe wholesale capacity auction true-up for the
year 2002 related to the
wholesale prices. In the first quarter of2002. Through September 30, 2003, TCC recorded an additional $56$169
million regulatory asset and related revenues for stranded costs.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 was no way to quantifyare stranded costs. As discussed above, a defined process is requiredHowever, in order to determineMarch 2003, the
amountTexas Court of Appeals ruled that under the restructuring legislation,
other 2004 true-up items including the wholesale capacity auction
true-up regulatory asset, could be recovered regardless of the level of
stranded costs related to generation
facilityplant costs.
In July 2003, the PUCT Staff published their proposed filing package
for the 2004 true-up proceedings.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
planwholesale capacity auction true-up regulatory asset could require
adjustment.
In October 2003, a coalition of divestitureconsumer 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 duringrequesting 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 provided such a process.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 divestitureplant divestitures and the 2004 true-up proceeding are
completed, TCC can securitizewill file to recover PUCT-approved stranded costs and
other true-up amounts that are in excess of current securitized amounts.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 will beare recovered
through a non-bypassable rate surcharge collected by the regulated transmission and
distribution (T&D)T&D utility
over the lifeterm of the securitization bonds.
Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate
non-bypassable competitive transition charge to T&D utility customers.
In the event TCC and TNCwe are unable, after the 2004 true-up proceeding, to
recover all or a portion of theirour generation-related regulatory assets,
unrecovered fuel balances, stranded plant costs, andwholesale capacity
auction true-up regulatory assets, other restructuring relatedtrue-up items
and costs, it could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
Arkansas Restructuring - Affecting AEP and 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 for the first quarter of 2003.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 AEP and 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 deregulationrestructuring 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.
475 In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, alegislation enacted in March 2003 WV Legislative Bill
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
deregulationrestructuring in West VirginiaWV 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 applyreapply SFAS 71.
The result of reapplyingReapplying SFAS 71 in WV had an insignificant effect on results of
operations for the first quarter of 2003.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 market-to-market.
7.marked-to-market.
6. COMMITMENTS AND CONTINGENCIES
-----------------------------
Power Generation Facility
- Affecting AEP
AEP has entered into 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, L.P.Limited
Partnership (Katco), an unrelated unconsolidated special purpose entity.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 an aggregatearranged to
finance the Facility with debt financing commitment of $525up to $494 million and a capital structureequity
up to $31 million (approximately 6%) of which 3%
is equitythe Facility's acquisition cost
from investors with no relationship to AEP or any of its
subsidiaries and 97% is debt from a syndicate of banks. Katco was formed
to develop, construct, finance and lease a power generation facility to
AEP. KatcoAEP's subsidiaries.
Juniper will own the power generation facilityFacility and lease it to AEP after construction is
completed. The lease was originally intended towill be accounted fortreated as an operating lease therefore neitherfor financial
accounting purposes. Consequently, the facility norFacility and the related
obligations would beare not reported on AEP's balance sheet (see
discussion of potential consolidation issues later in this note).Consolidated Balance Sheet.
Payments under the operating lease are expected to commence in the first
quarter of 2004. AEP will in turn sublease the facilityFacility to Dow Chemical
Company (DOW). The use of KatcoJuniper allows AEP to limit its risk
associated with the power generation facilityFacility once the construction phase has been completed. In
addition, the lease allows AEP isto utilize certain tax benefits
associated with the construction agent for Katco. Construction is currently
scheduled to be completed by the first quarter of 2004, subject to
unforeseen events beyond AEP's control.Facility.
In the event the project is terminated before completion of
construction, AEP has the option to either purchase the facilityFacility for
100% of project costsJuniper's acquisition cost (in general, the outstanding debt and
equity associated with the Facility) or terminate the project and make a
payment to KatcoJuniper 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 facilityFacility and sell
the excess energy. AEP has agreed to purchase approximately 800 MW of
such excess energy from DOW. AEP will resell thathas also agreed to sell approximately
800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period
of 20 years.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 has certain contractual rights and obligations in connection
with providingwas obligated pursuant to the PPA to provide
replacement capacity, energy and other productsancillary 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 projectPPA 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 purchase agreementPPA and is owed liquidating damages of approximately $17.5 million.
The initial term of the operating lease between KatcoJuniper and AEP
commences on the commercial operation date (COD) of the facilityFacility and
continues for five years or, if earlier, until November 2006.June 2009. The lease
contains extension options subject to the approval of Katco, and if all extension options were exercised,
the total term of the lease would be 30 years. AEP's lease payments to
KatcoJuniper during the initial term and each extended term are sufficient
for KatcoJuniper 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 Katco. At the endinitial 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 eachthe 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
Katco'sJuniper's approval, purchase the facilityFacility at its original construction
cost, or sell the facility,Facility, on behalf of Katco,Juniper, to an independent
third party. If the facilityFacility is sold and the proceeds from the sale are
insufficient to repay Katco, AEPpay all of Juniper's acquisition costs, we may be
required to make a payment (not to Katco forexceed $396 million) to Juniper of
the difference betweenexcess of Juniper's acquisition costs over the proceeds from the
sale, andprovided that AEP would not be required to make any payment if AEP
has made the obligations of Katco, up to 82% of the
project's cost.additional rental prepayment described below. AEP has
guaranteed a portion of the obligationsperformance of its subsidiaries to KatcoJuniper during the
construction and post-construction
periods.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 March 31,September 30, 2003, projectJuniper's acquisition costs subject to these agreementsfor the Facility
totaled $403$460 million, and total costs for the completed facilityFacility are
currently expected to be approximately $510$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 $12$18 million represent future
minimum payments during the initial term calculated using the indexed
LIBOR rate (1.38%(1.14% at December 31, 2002)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 Power Generation Facility collateralizesis collateral for the debt obligation
of Katco. AEP'sJuniper. Our maximum exposure to loss as a result of its involvementour financing
transaction with KatcoJuniper is 100%89.9% of Juniper's project costs during the
construction phase and up to 82%$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.
It is reasonably possible that under this operating lease structure AEP
will consolidate Katco in the third quarter of 2003, asAs a result of the
issuanceKatco's transfer of FASB Interpretation No. 46 "Consolidation of Variable
Interest Entities" (FIN 46). Upon consolidation, AEP would record the
assets, liabilities, depreciation expense, minorityits interest and debt
interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.
AEP is currently in the processFacility to
Juniper, we did not consolidate Juniper or any portion of reviewing restructuring options for
this operating lease, which could replace Katco with a new lease
facility. Under these new leasing options,the Facility
in accordance with FIN 46,
AEP would not consolidate the assets or debt of the Power Generation
Facility.46.
Nuclear Plant Outages - Affecting AEP, I&M and TCC
In April 2003, engineers at STP, found a small quantity of powdery
residue during inspections conducted regularly
as part of refueling outages.outages, found wall cracks in two bottom mounted
instrument guide tubes of STP officials are working closely with the NRC to safely returnUnit 1. These tubes were repaired and the
unit returned to service. The NRC will review any corrective action prior to
its implementation and restartservice in August 2003. Our share of the unit.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. Management is unable to predictAfter repair of
damage caused by the length of time that the STP andfish intrusion, Cook Plant units may be unavailable or the costs of corrective actions at
this time. CookUnit 1 returned to
service in May and Unit 2 was already planned forreturned to service in June following
completion of a scheduled refueling outage
starting May 5. We have commitments to provide power to customers during
the outages. Therefore, we will be subject to fluctuations in the market
prices of electricity and purchased replacement energy could be a
significant cost.outage.
Federal EPA Complaint and Notice of Violation - Affecting AEP, 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 have beenare 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 AEPour 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 year20-year
period.
Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might
be triggered and the plant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant. The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997). In
2001, the District Court ruled claims for civil penalties based on
activities that occurred more than five years before the filing date of
the complaints cannot be imposed. There is no time limit on claims for
injunctive relief.
Management believes itsOn 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 replacementreplacement.
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 conformity withsignificant 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 intends1992 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 vigorously
pursueseparate 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 defense.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
- Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
SWEPCo and TCCThe 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 AEP'sour
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, AEPour
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 date isrequirements began in May 2003
for TCC and begin in May 2005 for SWEPCo.
AEP isWe 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 non-SCRother combustion control technologies on
a larger number of units. During 2001, 2002 and 2003, SCR technology
commenced operations on OPCo'sunits of Gavin, Plant. Installation of SCR technology on Amos, Mountaineer, Big Sandy and
Mountaineer
plants was completed and commenced operation in May 2002.Cardinal plants. Construction of SCR technology at certain other AEP
generating units continues. Non-SCROther 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.
The AEPOur NOx compliance plan is a dynamic plan that is continually reviewed
and revised as new information becomes available on the performance of
installed technologies and the cost of planned technologies. Certain
compliance steps may or may not be necessary as a result of this new
information. Consequently, the plan has a range of possible outcomes.
Our currentCurrent estimates indicate that AEP'sour 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 $918 million$1 billion has been spent through
March 31,September 30, 2003. Estimated compliance cost ranges and
amounts spent by registrant subsidiaries are as follows:
Estimated Amount
Compliance Costs Spent
(in millions)
AEGCo $ 24 $ 5
APCo 463 250
CSPCo 87 54
I&M 34 8
KPCo 176 164
OPCo 495-824 404
SWEPCo 37 23
TCC 5 5 Since compliance costs cannot be estimated with
certainty, the actual cost to comply could be significantly different
than thethese 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, they will have an adverse effect onthese costs would adversely affect future results of
operations, cash flows and possibly financial condition.
Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
On October 15, 2002, certain subsidiaries of AEP filed claims against
Enron and its subsidiaries in the bankruptcy proceeding filed by the
Enron entities which are pending in the U.S. Bankruptcy Court for the
Southern District of New York. At the date of Enron's bankruptcy,
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, thereEnron may
be
a dispute with Enron concerning our abilityattempt to continue utilizationreject certain of the agreements relating to the Bammel
storage facility and certain appurtenant pipelines under the
existing agreements.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 the gas, had entered into a financing arrangement in
1997 with Enron and a group of banks. These banks purported to have
certain rights to the gas in certain events of default. In connection with
AEP'sour 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 this cushion gas purportedly in the Bammel
storage facility which would permit them to cause the withdrawal of this gas
from the storage facility. In September 2002, HPL filed a general denial
and certain counterclaims against the banks. HPL also filed a motion to
dismiss.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 AEP's financial position,our results of operations, cash flows and cash
flows.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, AEPwe 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 has recently instituted proceedingsfiled a complaint in the Bankruptcy Court
against other energy trading
counterpartiesAEPES challenging the practiceAEP's offsetting of utilizing offsetting receivables and payables
and related collateral across various Enron entities.entities and seeking payment
of approximately $125 million plus interest. We believe that we have thewill assert our right to
utilize similar
procedures in dealing with payables, receivables and collateral with
Enron entities by offsettingoffset trading payables owed to various Enron entities against trading
receivables due to several AEP subsidiaries. An
additional expense of up to $110 million may be incurred without such
offsets. We believe we have legal defenses to any challenge that may be
made to the utilization of such offsets but at this time areManagement is unable to
predict the ultimate resolutionoutcome of this issue.lawsuit or its impact on our results of
operations, cash flows or financial condition.
Shareholder Lawsuits - Affecting AEP
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 AEPwe failed to disclose that alleged "round
trip" trades resulted in an overstatement of revenues, that AEPwe failed to
disclose that AEPour traders falsely reported energy prices to trade
publications that published gas price indices and that AEPwe failed to
disclose that itwe did not have in place sufficient management controls to
prevent round trip"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 AEP executives, members of the AEP Board of Directors and AEP'sour
independent auditor. AEP
intendsWe 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.
Also inIn the fourth quarter of 2002, two shareholder derivative actions were
filed in state court in Columbus, Ohio against AEP and its Board of
Directors alleging a breach of fiduciary duty for failure to establish
and maintain adequate internal controls over AEP'sour gas trading operations; and,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 AEP 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. The
derivativeIn these actions, the plaintiffs seek recovery of
an unstated amount of compensatory damages, attorney fees and the ERISA actions are in the initial pleading
stage. AEP intendscosts. We
intend to vigorously defend against these actions.
California Lawsuit
-Affecting AEP
In November 2002, Cruz Bustamante,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.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 motion to
dismiss.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 this action.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 - Affecting AEP
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
deals and has claimed approximately $25$34 million iswas owed to BOM by AEP which BOM subsequently has changed to approximately $34 million.AEP. In
April 2003, AEPwe 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 in March 2003just prior to the
termination and liquidation that it owed AEPus approximately $68 million.
Alternatively, AEP isWe are claiming that BOM owes us approximately $45 million to AEP.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
- Affecting AEP
In October 2002, AEPwe filed itsa demand for arbitration with the American
Arbitration Association to initiate formal arbitration proceedings in a
dispute with the Williams Companies (Williams). The proceeding resultsresulted
from Williams' repudiation of its obligations to provide physical power
deliveries to AEP and Williams' failure to provide the monetary security
required for natural gas deliveries by AEP. Consequently, both parties
claimed default and terminated all outstanding natural gas and electric
power trading deals among the various Williams and AEP affiliates.
Williams claimed that AEP oweswe owed approximately $130 million in connection
with the termination and liquidation of all trading deals. Williams and
AEP believes
it has valid claims arising from Williams' actionssettled the dispute and is seeking, in
part, a determination that either no amount is due or that a lesser
amount is due from AEPwe paid $90 million to Williams (which lesserin June
2003. The settlement amount is fully
reserved by AEP) andapproximated the extentamount payable that, in the
ordinary course of any other damages and legal or
equitable relief available. Although management is unable to predictbusiness, we recorded as part of our trading activity
using MTM accounting. As a result, the outcomeresolution of this matter it isdid not expected to
have a material impact on results of operations cash flows or financial condition.
Arbitration of PG&E Energy Trading, LLC Claim - Affecting AEP
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. Although management is unableIn July 2003, AEP and PGET agreed to predicta
settlement and we paid approximately $11 million to PGET. The settlement
amount approximated the outcomeamount payable that, in the ordinary course of
this matter, it isbusiness, we recorded as part of our trading activity using MTM
accounting. As a result, the settlement payment did not expected to have a material
impact on results of operations, cash flows or financial conditions.condition.
Energy Market Investigation - Affecting AEP
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. AEP's managementManagement responded to the
inquiries and provided the requested information.information and has continued to
respond to supplemental data requests in 2003.
In March 2003, AEPwe received a subpoena from the SEC as part of the SEC's
ongoing investigation of energy trading activities. In August 2002, AEPwe
had received an informal data request from the SEC seekingasking that AEPwe
voluntarily provide information. The subpoena seekssought additional
information and is part of the SEC's formal investigation. AEPWe responded
to the subpoena and will continue to cooperate with the SEC.
OtherOn 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 subsidiary registrants continueStandard 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 involvedoperated by
independent administrators of the grid in certain
other matters discussedall 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, Annual Report.
8. GUARANTEES
In NovemberFERC 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 FASB issued FASB Interpretation No. 45,
"Guarantor's AccountingNorth 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 Disclosure Requirementscompliance time frames, and were
approved by the NERC ballot body in June 2003. We have developed
financial requirements for Guarantees,
Including Indirect Guaranteessecurity implementation and compliance with
these NERC standards, the costs of Indebtednesswhich are not expected to be material
to our future results of Others" (FIN 45) which
clarifies the accounting to recognize a liability related to issuing a
guarantee, as well as additional disclosures of guarantees. This new
guidance is an interpretation of SFAS 5, 57,operations and 107 and a rescission of
FIN 34. The initial recognition and initial measurement provisions of
FIN 45 is effective on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements of FIN 45
were effective for financial statements of interim or annual periods
ending after December 15, 2002.cash flows.
7. GUARANTEES
----------
There are no liabilities recorded for all of the guarantees described
below in accordance with FIN 45 as these guarantees were entered into prior to
December 31, 2002 or havein accordance with FIN 45. There are certain
liabilities recorded for guarantees entered into subsequent to December
31, 2002. These liabilities are immaterial values which were not
recorded.to AEP. There is no
collateral held in relation to theseany guarantees and there is no recourse
to third parties in the event theseany guarantees are drawn.
Certaindrawn 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 atby AEP or a subsidiary
level of
AEP in the subsidiaries' ordinary course of business. TCC issued one of
the LOCs for credit enhancement of issued bonds. At March 31,September 30, 2003, the maximum
future payments offor all the LOCs are approximately $158$181 million with
maturities ranging from AprilSeptember 30, 2003 to January 2011. Included in
these amounts is TCC's LOC was
forof approximately $40.9 million with a
maturity date of November 2003. I&M's LOC was approximately $2 million with a maturity date of March
2003. Since AEP isAs the parent toof all these subsidiaries,
it holdswe hold all assets of the subsidiaries as collateral. There is no
recourse to third parties in the event these letters of credit are
drawn.
The following AEP subsidiaries have entered into guarantees of third
parties obligations: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.
Additionally, CSWAEP Utilities
AEP Utilities guaranteed 50% of the required debt service reserve for
Polk Power Partners, anotheran IPP of which CSW Energy owns 50%. In the event
that Polk Power does not make the required debt payments, CSWAEP 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.contractor, Sabine Mining Company (Sabine). In the event the mining contractorSabine
defaults under any of these agreements, SWEPCo's total future maximum
payment exposure is approximately $73$60 million with maturity dates
ranging from April 2003June 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 March 31,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 13 "Minority Interest in Finance Subsidiary"6 "Commitments and
Contingencies" for disclosure for
the guaranteed support of AEP for Caddis Partners, LLC.
AEP and its subsidiaries enterrelated 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, AEP'sour exposure generally does
not exceed the sale price. AEPWe 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
quarternine months of 2003, AEPwe entered into several sale agreements as discussed
in Note 10.8. These sale agreements include indemnifications with a maximum
exposure of approximately $60$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 due to the insignificant fair value of the
indemnification or due to the fact that they were entered prior to December 31, 2002.
AEP and its subsidiariesWe 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 March 31,September 30, 2003, the maximum potential loss for these lease
agreements was approximately $25$27 million assuming the fair market value
of the equipment is zero at the end of the lease term.
The
maximum potential loss by registrant is as follows:
Maximum Potential Loss
Subsidiary (in millions)
APCo $ 0.7
CSPCo 0.5
I&M 3.3
KPCo 0.7
OPCo 2.7
PSO 2.9
SWEPCo 3.1
TCC 5.8
TNC 2.2
Other AEP Subsidiaries 3.5
Total $25.4
9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
In response to difficult conditions in AEP's business, a Sustained
Earnings Improvement (SEI) initiative was undertaken company-wide in the
fourth quarterSee Note 10 "Leases" for disclosure of 2002, as a cost-saving and revenue-building effort to
build long-term earnings growth. Termination benefits expense relating
to 1,120 terminated employees totaling $75.4 million pre-tax was
recorded in the fourth quarter of 2002. Of this amount, AEP paid $9.5
million and $51.2 million to these terminated employees in the fourth
quarter of 2002 and the first quarter of 2003, respectively. The
termination benefits expense was classified as Maintenance and Other
Operation expense on AEP's Consolidated Statements of Operations and as
Other Operation expense on the other registrants' statements of
operations. No additional termination benefits expense related to the
SEI initiative was recorded during the first quarter of 2003.
The following table shows the beginning and ending termination benefits
accrual amounts and the total termination related payments made during
the first quarter 2003.
Total Termination Total Termination
Payments Made During Benefits
Total Termination the Accrued at 3/31/03
Benefits Three Months (in millions)
Subsidiary Accrued at 12/31/02 Ended 3/31/03
Company (in millions) (in millions)
AEGCo $ 0.3 $ 0.3 $ -
APCo 12.2 9.3 2.9
CSPCo 4.5 3.8 0.7
I&M 13.1 9.3 3.8
KPCo 2.5 1.8 0.7
OPCo 7.1 5.4 1.7
PSO 3.0 2.4 0.6
SWEPCo 3.1 2.8 0.3
TCC 5.5 5.5 -
TNC 1.6 1.6 -
Other Subsidiaries
13.0 9.0 4.0
Totals $65.9 $51.2 $14.7
10.lease residual value guarantees.
8. DISPOSITIONS, DISCONTINUED OPERATIONS, AND ASSETS HELD FOR SALE AND IMPAIRMENTS
---------------------------------------------------------------------------
DISPOSITIONS
InDispositions During the First Half of 2003
During the first quartersix months of 2003, AEPwe completed a number of asset
dispositions determined not to be part of its core Utility Operations:
Disposition of Assetsthe sales of C3
Communications, On February 28,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 C3 Communications soldwas not significant.
Eastex
We completed the majoritysale of its assetsEastex during the third quarter of 2003. We
provided for a sales price of $7.25 million. C3 received $7 million in cash and a
one-year non-interest bearing note receivable of $250,000 from the
purchaser. AEP provided for an $82$218.7 million pre-tax asset impairment in the fourth
quarter 2002, and the effect of the sale on firstthird quarter 2003 results
of operations was not significant. Disposition of Mutual Energy Companies
On December 23, 2002, AEP received PUCT regulatory approval on a sale of
two of its Texas retail energy providers (REP's). As part of the REP
sale, MESC received a prepayment of approximately $30 million from the
purchaser. The prepaid service revenue was deferred on the books of MESC
to be amortized over the two-year term of the back office service
agreement.
On February 28, 2003, AEP completed the sale of Mutual Energy Service
Company, LLC (MESC) for $30.4 million dollars and realized a pre-tax
gain of approximately $12.2 million dollars. In addition, the $27.2
million pre-tax gain which was previously deferred and was being
recognized over the two-year term of a back office service agreement was
recognized as part of the gain calculation in the first quarter of 2003
as no further service obligations existed for MESC.
Disposition of Water Heater Assets
AEP sold its water heater rental program for $38 million and recorded a
pre-tax loss of $3.9 million in the first quarter of 2003 based upon
final terms of the sale agreement. AEP had provided for a $7.1 million
pre-tax charge in the fourth quarter 2002 based on an estimated sales
price ($3.2 million asset impairment charge and $3.9 million lease
prepayment penalty). AEP, APCo, CSPCo, I&M, KPCo, and OPCo operated a
program to lease electric water heaters to residential and commercial
customers until a decision was reached in the fourth quarter of 2002 to
discontinue the program and offer the assets for sale. See table below
for detail of charges by Company:
Asset Impairment Lease Prepayment Loss on Sale
Charge Recorded Penalty Recorded Recorded in First Quarter
Subsidiary in Fourth Quarter in Fourth Quarter 2003 (Pre-tax)
Company 2002 (Pre-tax) 2002 (Pre-tax)
(in millions)
APCo $0.050 $0.062 $0.056
CSPCo 0.615 0.758 0.740
I&M 0.643 0.792 0.787
KPCo 0.011 0.011 0.011
OPCo 1.757 2.163 2.165
Other Non- Registrant
Subsidiaries
0.126 0.156 0.161
Total $3.202 $3.942 $3.920
Disposition of AEP Gas Power Systems
In 2001, AEP acquired a 75% interest in a startup company, seeking to
develop low-cost peaking generator sets powered by surplus jet turbine
engines. In January 2003, AEP Gas Power Systems, LLC (Gas Power) sold
its assets. AEP recognized a goodwill impairment loss of $12.2 million
in the first quarter of 2002, and the effect of the asset sale on the
first quarter 2003 results of operations was not significant.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 classifiedreclassified as Discontinued Operations for all periods
presented. The assets and liabilities of Pushan Power Plant and Eastex
were
aggregated on AEP'sour Consolidated Balance Sheets as Assets Held for Sale
and Liabilities Held for Sale (see table at the end of the Assets Held
Forfor Sale section below for more detailed information):
For the quarter ended September 30, 2003 and 2002:
Pushan Power
SEEBOARD CitiPower Plant Eastex Total
Eastex-------- --------- ------------ ------ -----
(in millions)
2003 Revenue $ - $ - $15 $31 $ 46$- $- $14 $12 $26
2002 Revenue 383 97 15 12 507- (2) 18 22 38
2003 Earnings
(Loss) After Tax $ - $ - $ - $(9) $(9)$- $- $- $- $-
2002 Earnings
(Loss) After Tax 33 (11) 2 (2) 2246 (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, AEP (and its
registrant subsidiaries, as applicable)we recorded an estimated
loss on disposal of assets held for sale. Eastex
In 1998, CSW began constructionThe following provides an
update of a natural gas-fired cogeneration
facility (Eastex) located near Longview, Texas and commercial operations
commenced in December 2001. In June 2002, AEP requested that the FERC
allow it to modify the FERC Merger Order and substitute Eastex as a
required divestiture under the order, due to the fact that the agreed
upon market-power related divestiture of a plant in Oklahoma was no
longer feasible. The FERC approved the request at the end of September
2002. Subsequently, in the fourth quarter of 2002, AEP solicited bids
for the sale of Eastex and several interested buyers were identified by
December 2002. Wethose assets still anticipate that the sale of assets will be
completed by the end of 2003. The estimated pre-tax loss on sale of
$218.7 million, which was based on the estimated fair value of the
facility and indicative bids by interested buyers, was recorded in
Discontinued Operations in AEP's Consolidated Statements of Operations
during the fourth quarter 2002.
Results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144. The assets and liabilities of
Eastex have been included on AEP's Consolidated Balance Sheets as held for sale.
See the tables at the end of this section for more detailed
information.
Pushan Power Plant
In the fourth quarter of 2002, AEP began activeWe currently anticipate that negotiations to sell itsour interest in the
Pushan Power Plant (Pushan) in Nanyang, China to one of the minority
interest partners. We currently anticipate negotiations topartners will be completed by the end of 2003 with an estimated pre-tax loss on
disposal of $20.0 million, based on an indicative price expression. This
estimated loss was recorded in Discontinued Operations in AEP's
Consolidated Statements of Operations during the fourthsecond quarter of 2002.2004. 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 classifiedreclassified on AEP'sour
Consolidated Balance Sheets as heldAssets Held for sale.Sale and Liabilities Held
for Sale. See the tables at the end of this section for more detailed
information.
Telecommunications
AEP had developed businesses to provide telecommunication services to
businesses and to other telecommunication companies through broadband
fiber optic networks operated in conjunction with AEP's electric
transmission and distribution lines. The businesses included AEP
Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50%
share of AFN Networks, LLC (AFN), a joint venture. Due to the difficult
economic conditions in these businesses and the overall
telecommunications industry, and other operating problems, the AEP Board
approved in December 2002 a plan to cease operations of these
businesses. AEP initiated steps to market the assets of the businesses
to potential interested buyers in the fourth quarter of 2002. As a
result, the assets of C3 were sold in February 2003. See "Disposition of
Assets of AEP Communications" earlier in this note for further
information.
The sale of all telecommunication assets is expected by the end of 2003
with an estimated pre-tax impairment loss of $76 million related to AEPC
and an estimated pre-tax loss in value of the investment in AFN of $13.8
million. The estimated losses are based on indicative bids by potential
buyers. The estimated losses were recorded in Investment Value and Other
Impairment Losses in AEP's Consolidated Statements of Operations during
the fourth quarter 2002.
Newgulf Facility
In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation
facility located near Newgulf, Texas (Newgulf). In October 2002, AEP
began negotiations with a likely buyer of the facility. AEP still
expects a sale to be completed by the end of 2003 with an estimated
pre-tax loss on sale of $11.8 million based on an indicative bid by the
likely buyer. This loss was recorded as Asset Impairments on AEP's
Consolidated Statements of Operations during the fourth quarter 2002.
Newgulf's Property, Plant and Equipment, net of accumulated
depreciation, has been classified on AEP's Consolidated Balance Sheets
as held for sale. See the tables at the end of this section for more
detailed information.
Nordic Trading
In October 2002, AEP announced that its ongoing energy trading
operations would be centered around its generation assets. As a result,
AEP took steps to exit its coal, gas, and electricity trading activities
in Europe, except for those activities necessary to support the U.K.
Generation operations. The Nordic Trading business acquired earlier in
2002, was made available for sale to potential buyers. The estimated
pre-tax loss on disposal in 2002 of $5.3 million consisted of impairment
of goodwill of $4.0 million and impairment of assets of $1.3 million,
and was included in Asset Impairments on AEP's Consolidated Statements
of Operations during the fourth quarter of 2002. Management's
determination of a zero fair value at the end of 2002 was based on
discussions with a potential buyer. The assets and liabilities of Nordic
Trading have been classified on AEP's Consolidated Balance Sheets as
held for sale. The transfer of the Nordic Trading business, including
the trading portfolio, to new owners was completed during the second
quarter of 2003 and the impact on earnings during the second quarter of
2003 will not be significant.
Excess Equipment
In November 2002, as a result of a cancelled development project, AEPwe
obtained title to a surplus gas turbine generator. AEP has been
unsuccessful in finding potential buyersWe anticipate the
sale of the unit, including its own
internal generation operators, due to an over-supply of generation
equipment available for sale. Sale of the turbine is currently still
projected before the end of 2003 with an estimated 2002 pre-tax loss on
disposal of $23.9 million, based on market prices of similar equipment.
This estimated loss was recorded in Asset Impairments on AEP's
Consolidated Statements of Operations during the fourth quarter of 2002.2003. The Other Assets have been
classifiedreclassified on AEP'sour Consolidated Balance Sheets as heldAssets Held for sale.Sale.
See the tables at the end of this section for more detailed information.
Excess Real Estate
In the fourth quarter of 2002, AEPwe began to market an under-utilized
office building in Dallas, TX obtained through the merger with CSW. SaleWe
currently anticipate the sale of the facility is still projectedto be completed by the end
of 2003 and an estimated
pre-tax loss on disposal of $15.7 million was recorded during the fourth
quarter of 2002 based on an estimated sales price. This estimated loss
was included in Asset Impairments on AEP's Consolidated Statements of
Operations.2003. The property asset has been classifiedreclassified on AEP'sour Consolidated
Balance Sheets as heldAssets Held for sale.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 March 31,The assets and liabilities of the entities held for sale at September
30, 2003 and December 31, 2002 are as follows:
Pushan
Power Plant Newgulf Nordic Excess Excess
Eastex Facility TradingPlant Real Estate Equipment Total
At March 31,------ ----------- --------- -----
September 30, 2003 (in millions)
Assets:
------------------
Assets:
Current Assets $20 $ 16 $ - $50 $ - $ - $ 86$- $- $20
Property, Plant and
Equipment, Net - 149 6 -144 18 - 173
Deferred Income
Taxes - - - 6 - - 6162
Other Assets - - - 3 - 12 1512
----- ---- ---- -----
Total Assets Held
for Sale $20 $165 $ 6 $59$164 $18 $12 $280$194
===== ==== ==== =====
Liabilities:
Current Liabilities $ 6 $ 22 $ - $56 $ - $ - $ 84$26 $- $- $26
Long-term Debt - 2220 - - 20
Other Liabilities 52 - - 22
Other Liabilities 4 49 - 2 - - 5552
----- ---- ---- -----
Total Liabilities
Held Forfor Sale $10 $ 93 $ - $58 $ - $ - $161$98 $- $- $98
===== ==== ==== =====
Pushan Excess Water
Tele-
Power Newgulf Nordic Real Excess Heater communica-
EastexTele-
Plant Facility Trading Estate Equipment Program tionscommunications Total
At------ -------- ------- ------ --------- ------- -------------- -----
December 31, 2002 (in millions)
Assets:
-----------------
Assets:
Current Assets $15 $ 19 $ -$19 $- $35 $ - $ - $ 1 $ - $ 70$- $- $1 $- $55
Property, Plant and
Equipment, Net
- 132 6 - 18 - 38 6 200
Other Assets - - - 10 - 12 - - 22
----- --- ---- ---- ---- ---- --- -----
Total Assets
Held for Sale $15 $151 $ 6$6 $45 $18 $12 $39 $ 6 $292$6 $277
===== === ==== ==== ==== ==== === =====
Liabilities:
Current Liabilities $ 8 $ 28 $ -$28 $- $48 $ - $ - $ - $ - $ 84$- $- $- $- $76
Long-term Debt - 25 - - - - - - 25
Other Liabilities 4 26 - 3 - - - - 3329
----- --- ---- ---- ---- ---- --- -----
Total Liabilities
Held Forfor Sale $12 $ 79 $ -$79 $- $51 $ - $ - $ - $ - $142$- $- $- $- $130
===== === ==== ==== ==== ==== === =====
11. BUSINESS SEGMENTS
In October 2002, AEP announced thatIMPAIRMENTS
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 exiting wholesale markets where it
does not own assets and announced certain reassignment changes in membersdetermined that an other than temporary
impairment existed on two of the Officeequity investments. The impairment was
the result of the Chairman group.measurement of fair value that was triggered by our
recent decision to sell the assets. A further decision$70.0 million pre-tax ($45.5
million net of tax) charge was later maderecorded in September 2003 by the
Board of Directors and management to focus on AEP's core electric utility
businesses. Assets outside of domestic generation, distribution and transmission
of electricity are considered to be non-core and are being evaluated and may be
sold when market conditions are more favorable. In the fourth quarter of 2002,
as more fully described in Note 13 of the 2002 Annual Report, management
recognized pre-tax impairments totaling $1.4 billion, principally related to
non-regulated assets and investments and characterized $247 million of assets
and investments as Held for Sale.
During 2001 and most of 2002, AEP was in the process of restructuring into two
main businesses, i.e. the regulated business and the non-regulated business. The
extent to which these were to be further divided into business segments was
dependent on how the businesses were to be managed and how the chief operating
decision maker of each business would monitor the performance of such
businesses. However, until deregulation developed further, regulatory hurdles
were cleared and corporate separation was achieved, management was unable to
determine precisely what segments would exist for the various businesses after
corporate separation.
As a result of
the changes in AEP's business strategy noted above, management's
desire to concentrate on its core businesses, delays in corporate separation and
the repeal of and/or delay of competition and deregulation in AEP's
jurisdictions, a decision was made to realign the segments for financial
reporting purposes in the first quarter of 2003 to reflect the manner in which
AEP's chief operating decision makers (the Officeother than temporary impairment of the Chairman group) now
manage the business. Assets have been identified as either being core or
non-coreequity 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 and are being managed as such and the results of operations
are reported to senior managementincluded in this format as well as to AEP's investors
in its earning releases and presentations to financial analysts.
Throughout 2002, AEP's segments for financial reporting purposes were Wholesale,
Energy Delivery and Other. Theour "Investments - Other" business
activities were as follows:
Wholesale
- - Generation of electricity for sale to retail and wholesale customers - Gas
pipeline and storage facilities - Marketing and trading of electricity, gas,
coal and other commodities - Coal mining, bulk commodity barging operations and
other energy supply related businesses
Energy Delivery
- - Domestic electricity transmission
- - Domestic electricity distribution
Other
- - Energy services
- - Telecommunication services (reclassified as Held for
Sale as of December 31, 2002)
As a result of the Board of Director's and management's decision to concentrate
on its core asset base and exit wholesale operations where AEP does not own
assets, Wholesale will no longer be a reporting segment.
AEP's core operations
are now managed as vertically integrated electricity generation and energy
delivery businesses. The operations are managed on an integrated basis because
of the substantial impact of bundled, primarily cost-based rates and regulatory
oversight on the business process, cost structure and operating results. Assets
not meeting the Board of Director's and management's core strategy are
classified into three Investments segments. AEP's current segments, for which
discrete financial information is available, engage in business activities for
which AEP earns revenues and incurs expenses. The operating results of these
segments are regularly reviewed by AEP's chief operating decision maker. The9. 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
Management has aggregated electricity transmission, distributionThe tables below present segment information for the nine months ended
September 30, 2003 and generation
within Utility Operations because their economic characteristics are similar and
their revenue is substantially determined by regulated jurisdictions. AEP's
electricity transmission and distribution operations are entirely regulated by
FERC and state regulatory jurisdictions. Electric generation sales to retail
customers are determined by the respective state jurisdictions, even for
customers in Ohio, Texas and Virginia which are in transition to deregulation,
and whose transition rates are still determined by the respective state
jurisdictions.
With respect to Investments, management has aggregated data into three separate
reporting groupings, due to the significance of each business2002 and the manner in
which they are operated. The Investments-Gas Operations segment includes two
intra-state gas pipelinethree months ended September 30,
2003 and storage operations located in Louisiana and Texas
and also includes risk management activities around these assets. The
Investments-UK Operations segment includes the generation of electricity for
sale to wholesale customers in the UK. Investments-Other includes the coal
mining operations and commodity barging operations, all of which share similar
economic characteristics.
The tables below present the reformatted reportable segment information for the
three months ended March 31, 2003 and 2002 based on the changes in business
strategy in the first quarter of 2003.2002. These amounts include certain estimates and allocations
where necessary.
Investments
----------------------------------
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
March 31,---------- ---------- ---------- ----- ----------- ------------
Nine Months Ended September 30, 2003 (in millions)
Revenues from:
Revenues from:
External Customers $8,512 $2,791 $116 $439 $ 2,773 $1,102- $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 $ 50 $ 155 $- $ 4,080- $10,384
Other Operating Segments - 44192 - 13 (57)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) 528 (37) (55) 4372 (20) (51) (44) - 440257
Total Assets 28,840 4,513 1,493 1,775 280 (a) 36,901
March 31,29,262 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 $ 2,258 $433 $ 101 $ 200$2,940 $700 $53 $118 $- $ 2,992$3,811
Other Operating Segments - 4458 - 33 (77)42 (100) -
Discontinued Operations - - - 39 - 39
Cumulative Effect of
Accounting Changes,
net of tax - - - - - -
Net Income (Loss) 213 (48) 29 (363)405 5 (5) 20 - (169)425
Total Assets 25,056 6,241 1,648 6,905 793 (a) 40,643
(a) Reconciling adjustments for Total Assets include Assets Held for
Sale and/or Assets of Discontinued Operations.
All of the 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, which remains unchanged. 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 processes, cost structures and operating results.26,700 4,857 1,644 2,350 814(a) 36,365
Gross Property Additions 311 17 11 14 - 353
12.(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 unconsolidated special purpose entity. JMG has a capital structure of which
3% is equity from investors with no relationship to AEP or any of its
subsidiaries and 97% is debt from 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 uselease has an initial term of JMG allows OPCofive years and may be renewed
for up to enter intothree 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 while
keepingwith 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 capital lease. As
of March 31, 2003, unless the structure of this arrangement is changed,
it is reasonably possible that OPCo will consolidate JMGlessee obligation amount specified in the third
quarter of 2003 as a resultlease, which declines
over time from approximately 86% to 77% of the issuanceprojected fair market
value of FIN 46. Upon
consolidation, OPCo would record the assets, liabilities, depreciation
expense, minority interest and debt interest expenseequipment. At September 30, 2003, the maximum potential
loss was approximately $31.5 million ($20.5 million net of JMG. OPCo would
eliminatetax) 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 expense. OPCo's maximum exposurefor
up to loss as a
result of its involvement with JMG is approximately $460 million of
outstanding debt and equity of JMG as of March 31, 2003.
On March 31, 2003, OPCo made a prepayment of $90 million under this
operating lease structure. AEP recognizes lease expense on a
straight-line basis over the remaining lease term, in accordance with
SFAS 13 "Accounting for Leases". On March 31, 2003, due to the $90
million prepayment, the net lease liability became an asset of $67.8
million. The asset is comprised of $16.7 million included in Other
current assets and $51.1 million in Other Assets on AEP's Consolidated
Balance Sheets ($16.7 million in Prepayments and Other and $51.1 million
in Deferred Charges and Other Assets on OPCo's Balance Sheets) . The
asset will be amortized over the remaining lease term, which ends in the
first quarter of 2010.
13.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 InterstateIntrastate 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 iswas 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" -(Steelhead) for a non-controlling preferred member interest).interest. As managing
member, SubOne consolidatesconsolidated Caddis. Steelhead is an unconsolidated
special purpose entity and has ahad 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 use of Steelhead allows AEP to limit its
risk associated with Houston Pipe Line Company and Louisiana Intrastate
Gas Company.
Under the provisions of the Caddis formation agreements, Steelhead
receives a quarterly preferred return equal to an adjusted floating
reference rate (4.7426% and 4.4349% for the quarters ended March 31,
2003 and 2002, respectively). Caddis has the right to redeem Steelhead's
interest at any time.
The $750$525 million invested in
Caddis by Steelhead was loaned to SubOne. This intercompanyThe loan to SubOne is due
August 2006,2006.
On May 9, 2003, SubOne borrowed $225 million from AEP and is supportedused 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 natural gas pipeline assets of SubOne, a cash reserve fund of SubOne
and SubOne's $321.4 million ofconvertible preferred stock inof AEP Gas
Holding. The
preferred stock is convertible into AEP common stock uponHolding and the occurrence
of certain events including AEP's stock price closing below $18.75 for
ten consecutive trading days. AEP can elect not to have the transaction
supported by such preferred stock if SubOne were to reduce its loan with
Caddis by $225 million (see below).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 March 31,September 30, 2003, AEPSubOne has complied with the
covenants contained in the credit agreement. In addition, a default under any other agreement or
instrument relating tothe
acceleration of AEP and certain subsidiaries' debt outstanding, in
excess of $50 million, is an event of default under the credit
agreement.
The initial period of Steelhead's investment in Caddis is through August
2006. At the end of the initial period, Caddis will either reset
Steelhead's return rate, re-market Steelhead's interests to new
investors, redeem Steelhead's interests, in whole or in part including
accrued return, or liquidate Caddis in accordance with the provisions of
applicable agreements.
Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events, including a default in the payment of the
preferred return, Steelhead's rights include:include forcing a liquidation of
Caddis and acting as the liquidator, and requiring the conversion of the
AEP Gas Holding preferred stock into AEP common stock. If Steelhead
exercised its rights to force Caddis to liquidate under these
conditions, then AEP would evaluate whether to refinance at that time or
relinquish the assets that support the intercompany loan to Caddis.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.
The results of operations, cash
flows and financial position of Caddis and SubOne are consolidated with
AEP for financial reporting purposes. Steelhead's investmenthas deposited $414 million in Caddis
and payments made to Steelhead from Caddis are currently reported on
AEP's Consolidated Statements of Operation and Consolidated Balance
Sheets as Minority Interest in Finance Subsidiary.
On May 9, 2003, SubOne borrowed $225 million from AEP and reduced the
outstanding balance of the loan from Caddis, which Caddis then used to
reduce the preferred interest held by Steelhead. This payment will allow
the convertible preferred stock of AEP Gas Holding and the stock price
trigger discussed above to be eliminated.
AEP's maximum exposure to loss as a result of its involvement with
Steelhead is a $2 million capital investment, $83 million under the
subscription agreement to Caddis for any losses incurred by Caddis and
the cash reserve fund balance of approximately $42 million (as of March
31, 2003) due Caddis for default under the intercompany loan agreement.
Of the remaining $525 million financing, the recourse to AEP for the
first quarter will increase in the second quarter 2003 by $165 millionorder to
comply with certain covenants in the covenants.
As of March 31, 2003, AEP is continuing to review the application of FIN
46 as it relatescredit agreement. Pursuant to the
Steelhead transaction.
14. FINANCING AND RELATED ACTIVITIES
Long-term debt and other securities issuances and retirements
during the first threeterms 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:
Type
Principal Interest Due
Company Type of Debt Amount Rate Date
Issuances------- ------------ --------- -------- ----
(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 100 Variable 2005275 5.50 2013
TCC Senior Unsecured Notes 275 5.50 2013
TCC6.65 2033
TNC Senior Unsecured Notes 275 6.65 2033
TNC Senior Unsecured Notes 225 5.50 2013
Principal Interest Due
Company RetirementsType of Debt Amount Rate Date
------- ------------ --------- -------- ----
(in millions) (%)
Retirements:
AEP Bank Facility 1,300$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 3251 3.54 2005
Non-Registrant:
AEP SubsidiariesSubsidiary Notes Payable 2 Variable 20077 6.225 2017
AEP SubsidiariesSubsidiary Revolving Credit
Agreement 291306 Variable 2003
AEP SubsidiariesSubsidiary 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.
TypeAEP:
Principal Interest Due
Company Type of Debt Amount Rate Date
Retirements------- ------------ --------- -------- ----
(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 AprilMay 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 announced that they will haveCredit extended its sale of receivables agreement from its May 28,
2003 expiration to July 25, 2003, when the agreement was renewed for an
early redemptionadditional 364 days. The new sale of receivables agreement, which
expires on MayJuly 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 following:
o $125.5 million of CSPCo's First Mortgage Bonds
o $165 million of I&M's Junior Subordinated Debentures
o $90 million of I&M's First Mortgage Bonds
Consequently, the debt has been classified as Long-term Debt Due Within
One Yearretained interest
is based on their respective Balance Sheetsbook value due to the refinancing debt
having been issued prior to March 31, 2003.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, AEPwe 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.
REGISTRANTS' COMBINEDAEP 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 CONDITION, ACCOUNTING POLICIESDISCUSSION AND OTHER MATTERS
This is our combined presentationANALYSIS
----------------------------------------------
Results of management's discussion and analysis of
financial condition, accounting policies and other mattersOperations
- ---------------------
Net Income decreased $27 million for AEP and its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its registrant subsidiariesthe third quarter, but increased $43
million year-to-date. The decreased income for the quarter ended
March 31,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 is presentedCompared 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 their financial statements earlierthe 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 this
document.
FINANCIAL CONDITIONOperating 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
As discussed in the 2002 Annual Report, theThe rating agencies currently have been conducting
credit reviews of AEP and its registrant subsidiaries.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 InvestorsInvestor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review were downgradesincluded a downgrade
of the following ratingsTCC's rating for unsecured debt: AEP to Baa3 from Baa2, APCodebt from Baa1 to Baa2 PSOand secured debt from A2A3 to
Baa1, SWEPCo from A2 to Baa1 and TCC from Baa1 to Baa2.
TNC, which had no senior unsecured notes outstanding at the time of the ratings
action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial
paper was also downgraded from P-2 to P-3.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 its subsidiariesour
senior unsecured debt and first mortgage bonds ratings from BBB+ to BBB along withBBB.
Cash Flow
Cash flows for the first mortgage bonds of AEP subsidiaries. S&P
placed AEP on stable ratingnine months ended September 30, 2003 and closed their review.
In March 2003, Fitch Ratings Service downgraded the parent company (AEP) to BBB
from BBB+ with stable outlook.
Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the
following table:
Company Moody's S&P Fitch
APCo Baa1 BBB A-
CSPCo A3 BBB A
I&M Baa1 BBB BBB+
KPCo Baa1 BBB BBB+
OPCo A3 BBB A-
PSO A3 BBB A
SWEPCO A3 BBB A
TCC Baa1 BBB A
TNC A3 BBB A
Current short-term ratings are2002 were as
follows:
Company Moody's S&P Fitch
AEP P-3 A-2 F-2
The current ratings for senior unsecured debt are listed in the following table:
Company Moody's S&P Fitch
AEP Baa3 BBB BBB
AEP Resources* Baa3 BBB BBB+
APCo Baa2 BBB BBB+
CSPCo A3 BBB A-
I&M Baa2 BBB BBB
KPCo Baa2 BBB BBB
OPCo A3 BBB BBB+
PSO Baa1 BBB A-
SWEPCO Baa1 BBB A-
TCC Baa2 BBB A-
TNC Baa1 BBB A-
* The rating is for a series of senior notes issued with a Support Agreement
from AEP.
Liquidity
Liquidity, or access to cash, has become a more critical factor in determining
the financial stability of a company due to volatility in wholesale power
markets and the potential limitations that credit rating downgrades place on a
company's ability to raise capital. Management is committed to preserving an
adequate liquidity position and addressing AEP and its subsidiaries' financial
needs.
At March 31, 2003, we had an available liquidity position of $5.3 billion as
illustrated in the table below:
Credit Facilities
(in millions) Maturity
Commercial Paper Backup
Lines of Credit $2,500* 5/03
Commercial Paper Backup
Lines of Credit 1,000 5/05
Euro Revolving Credit
Facilities 315 10/03
Total 3,815
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 Liquidity Reserves 300**
Additional Unrestricted
Cash including Cash
on Hand for
Operational Needs 1,464**
Total Credit Facilities
and Cash 5,579
Less: Commercial Paper
Outstanding 225
Euro Revolving
Credit Loans 16
Total Available Liquidity $5,338
* Contains one year term-out provision.
** These components comprise the Cash and Cash Equivalents balance on AEP's
Consolidated Balance Sheet at March 31, 2003.
The Ohio and Texas subsidiaries issued $2.025 billion of senior unsecured notes
in February 2003 with maturity dates ranging from 2005 to 2033. The commercial
paper balance outstanding decreased due to its repayment with proceeds from
these issuances.
At December 31, 2002, AEP also had a $1.725 billion bank facility maturing in
April 2003 that was available for debt refinancing with $1.3 billion
outstanding. With the issuance of the permanent financing for the Ohio and Texas
subsidiaries, mentioned above, this facility was repaid and cancelled in
February 2003.
AEP also maintains a minimum $300 million cash liquidity reserve fund to support
its marketing operations in the U.S. and keeps additional cash on hand as market
conditions change. At March 31, 2002, AEP had $1.8 billion of available cash.
In total, as shown in the table above, we had approximately $5.6 billion in
liquidity sources of which $5.3 billion were unused and available at March 31,
2003.
In April 2003, AEP's Board of Directors declared a common stock dividend of
$0.35 per share for the second quarter of 2003, which is a 42% decrease from the
previous quarter's dividend of $0.60 per share. This reduction will result in
annual cash savings of approximately $395 million (based on the outstanding
common shares at April 30, 2003).
Cash from operations and short-term borrowings provide working capital and meet
other short-term cash needs. We generally use short-term borrowings to fund
property acquisitions and construction until long-term funding mechanisms are
arranged. Sources of long-term funding include issuance of common stock,
preferred stock or long-term debt and sale-leaseback or leasing agreements. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored receivables purchase agreement and two revolving credit
agreements.
Cash flowsflow from operating activities during the first quarter of 2003 were $775
million, including $335increased $198 million from depreciation, amortization, deferred income
taxes and deferred investment tax credits. This represents an increase of $795
million when compared to first quarter results of 2002, largelythe prior year
primarily due to the
year-over-yeara $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 $609$95 million ($440 millionin the current year were focused on
improved service reliability projects for transmission and $(169)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 2002, respectively) and an increase in cash from working
capital items of $985 million ($376$997 million in 20032002. Current
year debt proceeds replaced short and $(609) million in 2002).
The aforementioned increases were partially offset by a $(193) million
cumulative effect of accounting change in 2003 (see Note 3).
Cash flows used for investing activitieslong-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 quarternine months of 2003
were
$289 million compared to $332 million during the first quarterwere:
Issuances
---------
Principal Interest Due
Type of 2002. The
major reason for the year-over-year variance was proceeds of $35 million from
the sale of assets in 2003 (see Note 10). During the first quarter of 2003,
major construction expenditures continued for emission control technology at
several coal-fired generating plants (see Note 7).
Cash flows from financing activities in the first quarter of 2003 decreased by
$284 million when compared to the first quarter of 2002 ($65 million compared to
$349 million during 2003 and 2002, respectively), primarily as the result of
AEP's retirement and restructuring of its short-term and long-term debt during
2003. During the first quarter of 2003, AEP was able to retire $3,434 million of
debt ($2,925 million short-term and $509 million of long-term) and increase
available cash primarily through the issuance of long-term financing ($2,525
million), issuance of common stock ($1,177 million) and the generation of cash
from operating activities.
Total consolidated plant and property additions for the first quarter 2003 were
$324 million. The following table shows the plant and property additions by
certain registrant subsidiaries:
CompanyDebt Amount Rate Date
------------------ --------- -------- ----
(in millions) APCo $ 57
I&M 28
OPCo 56
SWEPCo 26
TCC 22
Financing Activity
Common Stock Offering
On February 27,(%)
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
AEP priced its offeringFirst 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
50 million shares of common
stock at a public offering price of $20.95 per share. AEP granted the
underwriters an option to purchase an additional 7.5 million shares of common
stock to cover over allotments.unregulated generation capacity in Texas. The underwriters exercised their over allotment
option to purchase an additional 6 million shares. The net proceeds of
approximately $1.1 billionvalue received from the sale of these securities were used to reduce
debt and for other corporate purposes.
Debt
During March 2003, AEP completed an offering of 5.375% Series C Senior Notes
which have a principal amount of $500 million and a maturity date of March 15,
2010. The net proceeds of $494 million from the offering were used to repay or
redeem current maturities of long-term debt and for other corporate purposes.
In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013
at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The
proceeds from the bond issuances were used to repay the bank facility due to
mature in April 2003, mentioned above, short-term debt and for other corporate
purposes.
During the first quarter of 2003, CSPCo retired $44 million of first mortgage
bonds due 2022 with rates ranging from 8.4% to 8.7%. SWEPCo and TCC retired $55
million and $16 million, respectively, of first mortgage bonds at maturity. TCC
also retired $32 million of securitization bonds due 2005.
In April 2003, SWEPCo issued $100 million of senior unsecured debt due 2015 at a
coupon of 5.375%.
In April 2003, certain AEP subsidiaries called the following First Mortgage
Bonds (FMB) or Junior Subordinated Debentures (JSD) for early redemption on May
30, 2003:
Coupon
Subsidiary Type of Or Stated Call Principal
Company Debt Rate Rate Due Date Amounts
% % (in millions)
APCo FMB 8.50 100 2022 $70
APCo FMB 7.15 100 2023 20
APCo FMB 7.80 103.90 2023 30
CSPCo FMB 6.55 100 2004 27
CSPCo FMB 6.75 100 2004 26
CSPCo FMB 7.75 104.27 2023 33
CSPCo FMB 7.90 103.95 2023 40
I&M FMB 8.50 100 2022 75
I&M FMB 7.35 100 2023 15
I&M JSD 8.00 100 2026 40
I&M JSD 7.60 100 2038 125
KPCo JSD 8.72 100 2025 40
In May 2003, a third party exercised its option to call $250 million of 5.50%
putable callable notes, issued by AEP in May 2001, for purchase and remarketing.
Management is evaluating alternatives and plans to exchange the notes.
During May 2003, APCo issued $200 million of unsecured senior notes due 2008 at
a coupon of 3.60% and $200 million of unsecured senior notes due 2033 at a
coupon of 5.95%. The proceeds of these bond issuancethis
disposition will be used to redeemcalculate our strande cost in Texas (see Note 4).
We expect to receive final bids in the aforementioned early redemptions for APCo, a floating rate note due in August
2003 and for other corporate purposes.
Possible Divestitures
We have a strong commitment to continually evaluate the need to reallocate
resources to areas that effectively match investments with our strategy, provide
greater potential for financial returns, and to disposefourth quarter of investments that no
longer meet these principles.
Assets we are seeking to divest consist of domestic and international
unregulated generation, gas pipelines, a coal business and a communications
business.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.
Corporate Separationoperations, 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 FERCdelivery
location.
(c)"Net Option Premiums Paid/(Received)" reflects the net option
premiums paid/(received) as they relate to unexercised and
SEC
seeking approvalunexpired 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 separatemarket
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
regulatedtotal 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 unregulated operations. Withgenerate 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 business strategy"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 responseour 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 energyperiod. 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
businessroll-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
continuesactivities.
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 evaluate corporate separation
plans,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 determining whether legal corporate separationcertain states in which the AEP
System's generating plants are located. The compliance date for the rules is appropriate.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 the
subsidiaries'AEP's transmission
systemssystem 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 subsidiaries, which operate inand other parties
continue to work on the statesresolution of Indiana, Kentucky, Ohio andthose conditions.
In December 2002, we filed with the Virginia filedSCC for state regulatory commission approval of their plansour plan to
transfer functional control of theirour transmission assets to PJM based on
statutory or regulatory requirements in those states. Those proceedings remain
pending.PJM. In February 2003,
the Virginia Legislature enacted legislation which the
Governor of Virginia signed, that prohibited the transfer of transmission assets
in its jurisdiction to an RTO until, at leastthe earliest, July 2004. In April 2003, FERC
approved AEP's transfer2004 and only with
the approval of functional control of the AEP East companies'
transmission system to PJM. FERC also accepted AEP's proposed rates for joining
PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings.
AEP West companiesVirginia SCC.
We are members of ERCOT or the SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and the SPP. AEP's
SPP companies are also regulated by state public utility commissions, and the
Louisiana and Arkansas commissions filed responses to the FERC's RTO order
indicating that additional analysis was required. Subsequently, the proposed
SPP/MISO combination was terminated. Regulatory activities concerning various
RTO issues are ongoing in Arkansas and Louisiana.
Management is unable to predict the outcome of these transmission regulatory actions and proceedings
or their impact on our transmission operations, results of operations and cash
flows or the timing and operation of RTOs our
transmission operations or results of operations and cash flows.
ACCOUNTING POLICIES(see Note 3).
Critical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Revenue Recognition
RegulatoryCritical Accounting - The consolidated financial statementsPolicies"
in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated
May 14, 2003) for a discussion of AEPthe estimates and judgments required for
revenue recognition, the valuation of long-lived assets, the accounting for
pension benefits and the financial statementsimpact of electric operatingnew 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 companiesregistrants. 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 cost-based
rate-regulated operations (I&M, KPCo, PSO,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 a portionunexpired
option contracts that were entered into in 2003.
(d)"Changes in Fair Value of APCo, CSPCo, OPCo,
SWEPCo, TCC and TNC) reflectRisk Management Contracts" represents the
actions of regulators that can resultfair value change in the recognitionrisk 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 revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expensesRisk Management Contracts Allocated to
be recovered inRegulated Jurisdictions" relates to the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effectsnet gains (losses) of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide for refunds to customers
that have not yet been made.
When regulatory assets are probable of recovery through regulated rates, we
record them as assets on the balance sheet. We test for probability of recovery
whenever new events occur, for example, issuance of a regulatory commission
order or passage of new legislation. If we determine that recovery of a
regulatory asset is no longer probable, we write-off that regulatory asset as a
charge against earnings. A write-off of regulatory assets may also reduce future
cash flows since there may be no recovery through regulated rates.
Electric Generation - We record operating revenues from electric generation
activities using accrual, hedge and mark-to-market methods of accounting.
We use accrual accounting for electricity sales to residential, industrial and
institutional customers who have not signed a contract or have entered into
long-term power salesthose
contracts that are not subject to mark-to-market
accounting. Under accrual accounting we record revenuesreflected 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 energy has been
delivered. Allthese 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
registrant subsidiaries except AEGCo are allocatedpoint at which a portion ofmarket is no longer liquid for placing it in the
revenues and costs associated with AEP's electric generation
activities that have been recognizedModeled category varies by market.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on an accrual basis.
Some contracts for the sale of electricity at fixed prices for future delivery
are used to mitigate the risk associated with anticipated sales of electricity
from our generation assets and have been designated and accounted for asBalance Sheet
The table provides detail on effective cash flow hedges under SFAS 133. Prior to settlement,133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we recordhave 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 contractsderivatives
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 Consolidated Statements
of Common Shareholders' Equity as Accumulated Other Comprehensive Income (AOCI).
When the anticipated sale of electricity occurs, the settlement amount of the
cash flow hedgenext twelve months is recorded in revenues. See Derivatives below.
Revenues recognized under the mark-to-market method of accounting include
realized revenue on electricity contracts, net of related costs of sales,a $1,167 thousand gain.
Credit Risk
The counterparty credit quality and unrealized gains and losses on electricity contracts accountedexposure for as
derivatives under SFAS 133. We also recognize revenues under the mark-to-market
method of accounting for non-derivative energy trading contracts as required by
EITF Issue No. 98-10. Beginning October 25, 2002 for new contracts and January
1, 2003 for pre-existing contracts, in accordance with a new accounting
pronouncement that is discussed further in Note 2, we discontinued the
mark-to-market method of accounting for all unsettled electricity contracts that
are not considered derivatives under SFAS 133. See Derivatives below. All of the registrant subsidiaries except AEGCo are allocatedis
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 portion$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 associated with AEP's electric generation activities; however, PSO,
SWEPCo, TCCof marketing
and TNC are only allocatedactivities 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 portion$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 forward transactions
that are accounted for usingAEP 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 mark-to-market method of accounting. We defer,
as regulatory liabilities (unrealized gains) or regulatory assets (unrealized
losses), changesprior period.
o An increase in the fair valueAEP system pool capacity charge of derivative contracts for the forward sale$5 million.
o A $13 million increase in Maintenance expense due primarily to
boiler overhaul work from scheduled and purchaseforced outages and
maintenance of electricityoverhead 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 traditional marketing areadecision 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 extent
thatone-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 jurisdiction is regulated. AEP's traditional marketing area is upculmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to two
transmission systems fromBBB along with the first
mortgage bonds of AEP service territory. For contracts which are
outside of AEP's traditional marketing area, the change in fair value is
included in nonoperating income on a net basis.
Electric Transmissionsubsidiaries.
Financing Activity
Long-term debt issuances and Distribution - Revenues from electricity transmission
and distribution services include realized revenue for electricity and delivery
services provided to residential, industrial and institutional customers. These
revenues are recognized when delivery services are provided.
Gas Sales, Pipeline and Storage Activities - Revenue from gas sales activities
includes realized revenue on contracts for the sale of gas, and unrealized gains
and losses on gas contracts accounted for as derivatives under SFAS 133. See
Derivatives below. Revenues from gas pipeline and storage services are
recognized when gas is delivered to contractual meter points or when services
are provided. Transportation and storage revenues also include the accrual of
earned, but unbilled and/or not yet metered gas.
Substantially all of the forward gas purchase and sale contracts (excluding
wellhead purchases of natural gas), swaps and options for the pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair valueretirements during the period are recognized currently in resultsfirst nine months of operations2003
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 are appropriately discounted, netNotice of applicable credit and
liquidity adjustments.
Derivatives - We use derivative instruments such as futures, swaps, forwards and
options to manage the commodity, currency exchange and financial market risks of
our business operations. We also manage a portfolio of commodity contracts held
for trading purposes as part of our strategy to market excess generation
capacity. All derivative instruments not qualifying for the normal purchase
normal sale exemption under SFAS 133 are recorded in the Consolidated Balance
Sheets as Risk Management Assets and Liabilities. On the date a derivative
instrument is entered into, we designate the derivative as either a normal
purchase or sale contract; as held for trading purposes (trading contract);
and/or a hedge of a forecasted transaction or future cash flows (cash flow
hedge).
Derivative instruments that provide for the purchase or sale of energy
commodities that will settle physically in the normal course of business qualify
for the normal purchase and sale exemption under SFAS 133. If the exemption has
been elected, no amount associated with these contracts is included in the
Consolidated Financial Statements until the commodity is actually delivered.
Derivative instruments used to mitigate the risks of variability in expected
cash flows attributable to a forecasted transaction are designated and accounted
for as cash flow hedges under SFAS 133. Cash flow hedges are recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
unrealized gains and losses recorded on the Consolidated Statements of Common
Shareholders' Equity as AOCI until the hedged item affects earnings. We formally
document the hedging relationship at the inception of the cash flow hedge and
assess whether the hedging relationship is highly effective in achieving
offsetting cash flows on an ongoing basis. We discontinue hedge accounting
prospectively when the cash flow hedge is determined to be ineffective in
achieving offsetting cash flows of the hedged item or it is not probable that
the hedged transaction will occur. Settled amounts and ineffective portions of
cash flow hedges are removed from AOCI and recorded in the Consolidated
Statements of Operations in the same accounts as the hedged item. When hedge
accounting is discontinued because the derivative no longer qualifies as an
effective hedge, the derivative instrument will continue to be recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
subsequent changes in fair value recognized in the Consolidated Statements of
Operations.
Derivative instruments entered into for trading purposes are recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
all realized and unrealized gains and losses presented on a net basis in the
Consolidated Statements of Operations.
Energy options, futures and swaps represent financial transactions with
unrealized gains and losses from changes in fair values reported net in
revenues. APCo, CSPCo, I&M, KPCo and OPCo also have financial transactions, but
record the unrealized gains and losses, as well as the net proceeds upon
settlement, in Nonoperating Income.
The fair values of derivative contracts are based on exchange prices and broker
quotes. We mark-to-market long-term derivative contracts based primarily on
valuation models that estimate future energy prices based on existing market and
broker quotes and supply and demand market data and assumptions. The fair values
determined are reduced by the appropriate valuation adjustments for items such
as discounting, liquidity and credit quality. Credit risk is the risk that the
counterparty to the contract will fail to perform or fail to pay amounts due.
Liquidity risk represents the risk that imperfections in the market will cause
the price to be less than or more than what the price should be based purely on
supply and demand. There are inherent risks related to the underlying
assumptions in models used to fair value open long-term contracts. We have
independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile. Volatility in energy commodities markets affects the fair values of
all of our open trading and derivative contracts exposing us to market risk and
causing our results of operations to be subject to volatility. Unforeseen events
can and will cause reasonable price curves to differ from actual prices
throughout a contract's term and at the time contracts settle. Therefore, there
could be significant adverse or favorable effects on future results of
operations and cash flows if our current estimates of future market prices are
not representative of actual future market prices. Differences between actual
market prices in the future and our estimated future prices are more likely to
occur for long-term contracts.
See the "Quantitative and Qualitative Disclosures About Risk Management
Activities" section of this report for a discussion of the policies and
procedures used to manage our exposure to market and other risks from trading
activities.
New Accounting Pronouncements
See Note 2 for a discussion of significant accounting policies and new
accounting pronouncements.
OTHER MATTERS
Industry RestructuringViolation
As discussed in the 2002 Annual Report restructuring(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 customer choice were
effectivea number of states
alleged CSPCo, certain affiliated companies and eleven unaffiliated utilities
made modifications to generating units at coal-fired generating plants in
fourviolation of the eleven state retail jurisdictionsClean 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
electric utility companies operate. Restructuring legislation providesSystem'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 transitiondiscussion 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 cost-based rate regulationone period to the next.
Roll-Forward of bundled electric serviceMTM 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 customer choiceValuation
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
pricingconditions.
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 supplyyear-over-year variance was a construction expenditures increase of electricity. The status$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 our transition plans, regulatory issues and proceedings and accounting issues in
the state regulatory jurisdictions impacted by restructuring and customer choice
is presented in Note 6.2003 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 - Affecting AEP, I&M and TCC
In April 2003, engineers at STP found a small quantity of powdery residue during
inspections conducted regularly as part of refueling outages. STP officials are
working closely with the NRC to safely return the unit to service. The NRC will
review any corrective action prior to its implementation and restart of the
unit.
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. Management is unable to predictAfter repair of damage caused by the length of time that the STP andfish
intrusion, Cook Plant units may be unavailable or the costs of corrective actions at this time. CookUnit 1 returned to service in May 2003 and Unit 2 was already planned forreturned
to service in June 2003 following completion of a scheduled refueling outage starting May 5. We have
commitments to provide power to customers during the outages. Therefore, we will
be subject to fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost.
Litigationoutage.
Federal EPA Complaint and Notice of Violation
- Affecting AEP, APCo, CSPCo, I&M,
and OPCo
As discussed in the 2002 Annual Report AEPSC, APCo, CSPCo, I&M, and OPCo have
been(as updated by the Current Report on Form
8-K dated May 14, 2003), we are involved in litigation since 1999 regarding generating
plant emissions under the Clean Air Act. The Federal EPA and a number of states
alleged APCo, CSPCo,
I&M, OPCocertain 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
75 for further discussion.
NOx Reductions
- Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and
TCCThe 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 date is May 2003 for TCC and May 2005 for SWEPCo.
AEP isWe are installing selective catalytic reduction (SCR) technology and non-SCRother
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$531 million to $1.7 billion
for the AEP System.$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, they will
have an adverse effect onthese costs would adversely affect future results of
operations, cash flows and possibly financial condition. See Note 75 for further
discussion.
Enron BankruptcyCritical Accounting Policies
See "Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corporation and its subsidiaries which is pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of Enron's
bankruptcy, AEP and its subsidiaries had open trading contracts and trading
accounts receivables and payables with Enron and various HPL related
contingencies and indemnities including issues related to the underground Bammel
gas storage facility and the cushion gas (or pad gas) required for its normal
operation.
Management believes that AEP entities have the right to utilize offsetting
receivables and payables and related collateral across various Enron entities by
offsetting trading payables owed to various Enron entities against trading
receivables due to us. Management believes we have legal defenses to any
challenge that may be made to the utilization of such offsets. An additional
expense of up to $110 million may be incurred without such offsets. At this time
management is unable to predict the ultimate resolution of these issues or their
impact on results of operations and cash flows. See Note 7 for further
discussion.
Bank of Montreal Claim - Affecting AEP
In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
deals and has claimed approximately $25 million is owed to BOM by AEP which
BOM subsequently has changed to approximately $34 million.In April 2003, AEP
filed a lawsuit against BOM claiming BOM had acted contrary to industry
practice in calculating termination and liquidation amounts and that
BOM had acknowledged in March 2003 that it owed AEP approximately $68 million.
Alternatively, AEP is claiming that BOM owes approximately $45 million to AEP.
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 - Affecting AEP
In 2002, AEP filed its demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
Although management is unable to predict the outcome of this matter, it is not
expected to have a material impact on results of operations, cash flows or
financial condition. See Note 7 for further discussion.
Arbitration of PG&E Energy Trading, LLC Claim - Affecting AEP
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.
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 conditions.
Energy Market Investigations - Affecting AEP
As discussedCritical Accounting Policies"
in the 2002 Annual Report (as updated by the FERC,Current Report on Form 8-K dated
May 14, 2003) for a discussion of the California attorney
general,estimates and judgments required for
revenue recognition, the PUCT,valuation of long-lived assets, the SEC, the Department of Justiceaccounting for
pension benefits and the U.S. Commodity
Futures Trading Commission (CFTC) initiated investigations into whether any
entity, including Enron Corporation, manipulated short-term prices in electric
energy or natural gas markets, exercised undue influence over wholesale prices
or participated in fraudulent trading practices.
In March 2003, the SEC subpoenaed information from its August 2002 request for
us to voluntarily provide certain trading information. AEPimpact of new accounting pronouncements.
Quantitative And Qualitative Disclosures About Risk Management Activities
- -------------------------------------------------------------------------
Market Risks
Risk management policies and its subsidiaries
haveprocedures are instituted and will continue to provide information to the FERC, the SEC, state
officials and the CFTC as required. See Note 7 for further discussion.
Shareholders' Litigation - Affecting AEP
In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against AEP, certain
AEP executives, members ofadministered at the
AEP Board of Directors and certain investment
banking firms. These cases are in the initial pleading stage. AEP intends to
vigorously defend against these actions.consolidated level for all subsidiary registrants. See Note 7 for further discussion.
California Lawsuit - Affecting AEP
In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP intends to
vigorously defend against this action. See Note 7 for further discussion.
COLI Litigation
A decision by the U.S. District Court for the Southern District of Ohio in
February 2001 that deniedcomplete discussion
within AEP's deduction of interest claimed on AEP's
consolidated federal income tax returns related to a COLI program resulted in a
$319 million reduction in AEP's Net Income for 2000. We filed an appeal of the
U.S. District Court's decision with the U.S. Court of Appeals for the 6th
Circuit. In April 2003, the Appeals Court ruled against AEP."Qualitative And Quantitative Disclosures About Risk Management
is
reviewing this opinion and will evaluate AEP's options.
Other Litigation
AEP and its subsidiaries continue to be involved in certain other legal matters
discussed in the 2002 Annual Report.
Snohomish Settlement - Affecting AEP
In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract 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.
Other Management Matters - Affecting AEP
On April 9, 2003, Dr. E. Linn Draper Jr., AEP's chairman,
president and chief executive officer, announced that he plans to retire in
2004. AEP's board of directors will soon begin the process of identifying
Dr. Draper's successor.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
Market Risks
As a major power producer and marketer of wholesale electricity and natural gas,
AEP has 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 AEP 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 AEP's day to day operations. AEP's 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.Activities" section. The following tables provide information on AEP'sabout the risk
management activities.
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 Assets
This table provides detail on changes in AEP's MTM net asset or
liability balance sheet position from one period to the next.
TABLE 1 Part I
Roll-Forward of MTM Risk Management Contract Net
Assets
Three Months Ended March 31, 2003
Domestic Domestic AEP
AEP Consolidated Power Gas International Consolidated
(in millions)
Beginning Balance December 31, 2002 $360 (155) 45 250
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (89) (23) (22) (134)
Fair Value of New Contracts When Entered
Into During the Period (day one gains) (b)
- - - -
Net Option Premiums Paid/(Received) (c) (2) 24 (2) 20
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 (e) 27 24 (28) 23
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (d)
17 - - 17
Ending Balance March 31, 2003 $294 $(128) $(21) $145
Domestic Power APCo CSPCo I&M KPCO
(in thousands)
Beginning Balance December 31, 2002 $96,852 $65,117 $70,861 $24,998
(Gain) Loss from Contracts Realized/Settled During
the Period (a) (25,745) (17,307) (16,202) (5,691)
Fair Value of New Contracts When Entered Into
During the Period (day one
gains) (b) - - - -
Net Option Premiums Paid/(Received) (c) (466) (274) (293) (106)
Change in Fair Value Due to Valuation Methodology
Changes - - - -
Effect of 98-10 Rescission (4,664) (3,135) (4,861) (1,744)
Changes in Fair Value of Risk Management
Contracts (e) 14,451 6,623 (296) (163)
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (d)
6,377 - 6,249 2,459
Ending Balance March 31, 2003 $ 86,805 $51,024 $55,458 $19,753
Domestic Power OPCo PSO SWEPCo TCC
(in thousands)
Beginning Balance December 31, 2002 $ 94,106 $ 3,545 $ 4,050 $ 5,414
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (24,661) 220 (18) (670)
Fair Value of New Contracts When Entered Into
During the Period (day one - - - -
gains) (b)
Net Option Premiums Paid/(Received) (c) (363) - - -
Change in Fair Value Due to Valuation Methodology
Changes - - - -
Effect of 98-10 Rescission (4,159) - 151 187
Changes in Fair Value of Risk Management
Contracts (e) 10,868 - 595 (4,527)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (d)
- 1,192 885 -
Ending Balance March 31, 2003 $ 75,791 $ 4,957 $ 5,663 $ 404
Domestic Power TNC
(in thousands)
Beginning Balance December 31, 2002 $ 2,043
(Gain) Loss from Contracts Realized/Settled During
the Period (a) (41)
Fair Value of New Contracts When Entered Into
During the Period (day one -
gains) (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 (e) (269)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (d) (298)
Ending Balance March 31, 2003 $ 1,455
(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)"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.
(e)"Changes in Fair Value of Risk Management Contracts" represents the
fair value change in the risk management portfolio due to market
fluctuations during the current period. Market fluctuations are
attributable to various factors such as supply/demand, weather,
storage, etc.
(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.
TABLE 1 Part II
Detail on MTM Risk Management Contract
Net Assets
As of March 31, 2003
Domestic Domestic AEP
Power Gas International Consolidated
(in millions)
Current Assets $ 473 $ 465 $ 157 $ 1,095
Non Current Assets 426 285 57 768
Total MTM Energy Assets $ 899 $ 750 $ 214 $ 1,863
Current Liabilities $(367) $(688) $(183) $(1,238)
Non Current Liabilities (238) (190) (52) (480)
Total MTM Risk Management Contract Liabilities $(605) $(878) $(235) $(1,718)
Total MTM Risk Management Contract Net Assets $ 294 $(128) $ (21) 145
Assets Held for Sale (Nordic) 17
Less Non-Trading Related Derivative Liabilities
(56)
Net Fair Value of Risk Management and Derivative
Contracts $ 106
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information.
o The source of fair value used in determining the carrying amount of AEP's total MTM asset
or liability (external sources or modeled internally)
o The maturity, by year, of AEP's net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash
TABLE 2 Part I
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31,September 30, 2003
Remainder After
US POWER:
2003 2004 2005 2006 2007 2007 Total
--------- ---- ---- ---- ---- ----- -----
(in millions)
thousands)
Prices Actively Quoted - Exchange
Traded Contracts $ (5) $(6) $ (2) $(2) $ - $ - $(15)$(219) $40 $(200) $- $- $- $(379)
Prices Provided by Other External
Sources - - OTC Broker Quotes (a) 52 58 21 14 74,218 13,368 4,668 4,093 969 - 15227,316
Prices Based on Models and Other
Valuation Methods (b) 33 19 11 20 17 57 1571,588 3,839 2,437 2,946 3,249 8,666 22,725
------- -------- ------- ------- ------- ------- --------
Total $ 80 $71 $ 30 $32 $24 $57 $294
U.S. GAS:
Prices Actively Quoted - Exchange
Traded Contracts (a) $ (39) $101 $ (6) $(1) $ - $ - $ 55
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 41 - - - - - 41
Prices Based on Models and Other
Valuation Methods (b) (193) (41) (4) 9 8 (3) (224)
Total $(191) $ 60 $(10) $ 8 $ 8 $(3) $(128)
International:
Prices Actively Quoted - Exchange Traded
Contracts (a) $ (14) $ (1) $ - $ - $ - $ - $(15)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) (12) 6 - (1) - - (7)
Prices Based on Models and Other
Valuation Methods (b) (1) - - - 1 1 1
Total $ (27) $ 5 $ - $(1) $ 1 $ 1 $(21)
AEP Consolidated:
Prices Actively Quoted - Exchange Traded
Contracts $ (58) $ 94 $ (8) $(3) $ - $ - $ 25
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 81 64 21 13 7 - 186
Prices Based on Models and Other
Valuation Methods (b) (161) (22) 7 29 26 55 (66)
Total $(138) $136 $ 20 $39 $33 $55 $145
APCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $16,282 $16,967 $5,722 $4,278 $1,949 $ - $45,198
Prices Based on Models and Other
Valuation Methods (b) 10,597 2,984 2,203 4,988 4,581 16,254 41,607
Total
$26,879 $19,951 $7,925 $9,266 $6,530 $16,254 $86,805
CSPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $ 9,569 $ 9,974 $3,364 $2,514 $1,145 $ - $26,566
Prices Based on Models and Other
Valuation Methods (b) 6,229 1,754 1,295 2,932 2,693 9,555 24,458
Total $15,798 $11,728 $4,659 $5,446 $3,838 $9,555 $51,024
I&M Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $11,490 $10,513 $3,599 $2,690 $1,226 $ - $29,518
Prices Based on Models and Other
Valuation Methods (b) 6,438 1,872 1,386 3,138 2,882 10,224 25,940
Total $17,928 $12,385 $4,985 $5,828 $4,108 $10,224 $55,458
KPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $3,705 $3,860 $1,302 $ 974 $ 443 $ - $10,284
Prices Based on Models and Other
Valuation Methods (b) 2,411 679 502 1,135 1,043 3,699 9,469
Total $6,116 $4,539 $1,804 $2,109 $1,486 $3,699 $19,753
OPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $19,450 $15,232 $4,462 $3,336 $1,520 $ - $44,000
Prices Based on Models and Other
Valuation Methods (b) 7,652 2,281 1,718 3,890 3,573 12,677 31,791
Total $27,102 $17,513 $6,180 $7,226 $5,093 $12,677 $75,791
PSO Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $ 943 $ 928 $330 $247 $112 $ - $2,560
Prices Based on Models and Other
Valuation Methods (b) 611 172 127 286 264 937 2,397
Total $1,554 $1,100 $457 $533 $376 $937 $4,957
SWEPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $1,077 $1,060 $377 $282 $128 $ - $ 2,924
Prices Based on Models and Other
Valuation Methods (b) 698 196 145 328 302 1,070 2,739
Total $1,775 $1,256 $522 $610 $430 $1,070 $ 5,663
TCC Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $ 77 $76 $27 $20 $ 9 $ - $209
Prices Based on Models and Other
Valuation Methods (b) 50 14 10 23 22 76 195
Total $127 $90 $37 $43 $31 $76 $404
TNC Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $277 $272 $ 97 $ 72 $ 33 $ - $ 751
Prices Based on Models and Other
Valuation Methods (b) 179 51 37 85 77 275 704
Total $456 $323 $134 $157 $ 110 $275 $1,455
(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$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 in Table 2 Part I varies by market. Table 2 Part II
reports an estimate of the maximum tenors of the liquid portion of each energy
market used to complete Table 2 Part I.
Table 2 Part II
Maximum Domestic Tenor of the Liquid Portion of Risk Management Contracts
As of March 31, 2003
TENOR
(in months)
Natural Gas Forward Purchase and Sales
NYMEX Henry Hub Gas 72
Gas East - Northeast, Mid-continent
Gulf Coast, Texas 12
Gas West - Permian Basin, San Juan,
Rocky Mtns, Kern, Cdn Border(Sumas),
Malin, PGE Citygate, AECO 12
Power (Peak) Over the Counter Options
Power East - Cinergy 33
Power East - PJM 33
Power East - First Energy 21
Power East - NEPOOL 21
Power East - ERCOT 21
Power East - TVA 9
Power East - Com Ed 9
Power East - Entergy 33
Power West - PV, NP15,SP15,MidC,Mead 57
Peak Power Volatility (Options) ECAR, MidCon, NYPP, PJM, West Ercot
NEPOOL 21
OffPeak Power Volatility All Regions 0
Natural Gas
Liquids 14
Emissions 33
Coal 33
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)
(AOCI) on the Balance Sheet
AEP employs fair value hedges and cash flow hedges to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. AEP does not hedge all interest rate risk.
AEP employs forward contracts as cash flow hedges to lock-in prices on certain
transactions which have been denominated in foreign currencies where deemed
necessary. International subsidiaries use currency swaps to hedge exchange rate
fluctuations of debt denominated in foreign currencies. AEP does not hedge all
foreign currency exposure.
Table 3The 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 haswe have in place. (However, given that under SFAS 133 not allonly cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of AEP's hedges)our hedging activity). The table further indicates what portionsalso 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 expected to roll off intorecorded in AOCI, the income statement in the next 12 months.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.
TABLE 3
Cash Flow Hedges included in Accumulated Other Comprehensive Income
On the Balance Sheet as of March 31, 2003
Portion Expected to
Accumulated Other Be Reclassified to
Comprehensive Income Earnings During the
(Loss) After Tax
(a) Next 12 Months (b)
AEP Consolidated (in millions)
Domestic Power $(43) $(31)
Domestic Gas 8 (3)
Foreign Currency 2 2
Interest Rate (5) 1
Total AEP $(38) $(31)
Total Other Comprehensive Income Activity
Three Months Ended March 31, 2003
Domestic Domestic Foreign AEP
Power Gas Currency Interest Rate Consolidated
(in millions)
Accumulated OCI, December 31, 2002 $ (1) $ - $(3) $(12) $(16)
Changes in Fair Value (c) (65) 8 5 6 (46)
Reclassifications from OCI to Net
Income (d) 23 - - 1 24
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(43) $ 8 $ 2 $ (5) $(38)
APCo Domestic Foreign AEP
Power Currency Interest Rate Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920)
Changes in Fair Value (c) (19,201) - (104) (19,305)
Reclassifications from OCI to Net
Income (d) 6,649 2 136 6,787
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(12,946) $(188) $(1,304) $(14,438)
CSPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (267)
Changes in Fair Value (c) (11,251)
Reclassifications from OCI to Net
Income (d) 3,908
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(7,610)
I&M Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (286)
Changes in Fair Value (c) (12,039)
Reclassifications from OCI to Net
Income (d) 4,182
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(8,143)
KPCo Domestic KPCo
Power Interest Rate Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (103) $425 $ 322
Changes in Fair Value (c) (4,357) (43) (4,400)
Reclassifications from OCI to Net
Income (d) 1,513 22 1,535
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(2,947) $404 $(2,543)
OPCo Domestic Foreign OPCo
Power Currency Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738)
Changes in Fair Value (c) (14,928) - (14,928)
Reclassifications from OCI to Net
Income (d) 5,185 3 5,188
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(10,097) $(381) $(10,478)
PSO Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (42)
Changes in Fair Value (c) (1,833)
Reclassifications from OCI to Net
Income (d) 636
Accumulated OCI Derivative Gain (Loss) March
31, 2003 $(1,239)
SWEPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (48)
Changes in Fair Value (c) (2,094)
Reclassifications from OCI to Net
Income (d) 727
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(1,415)
TCC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (36)
Changes in Fair Value (c) (1,559)
Reclassifications from OCI to Net
Income (d) 541
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(1,054)
TNC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (15)
Changes in Fair Value (c) (645)
Reclassifications from OCI to Net
Income (d) 224
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $ (436)
(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
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 (realized or unrealized) from
derivatives used as hedging instruments that have been deferred and
are expected to be reclassified into net income during the next 12
months at the time the hedged transaction affects net income.
(c) Changes in fair value - Changes in the fair value of derivatives
designated as hedging instruments in cash flow hedges during the
reporting period not yet reclassified into net income, pending the
hedged item's affecting net income. Amounts are reported net of
related income taxes.
(d) Reclassifications from AOCI to net income - Gains or losses
from derivatives used as hedging instruments in cash flow hedges that
were reclassified into net income during the reporting period. Amounts
are reported net of related income taxes above.
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
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 March 31, 2003. At March 31, 2003 approximately 6% of AEP's
exposure was below investment grade as expressed in terms of net MTM assets. Net
MTM assets represents the aggregate difference between the forward market price
for the remaining term of the contract and the contractual price per
counterparty. As of March 31, 2003 the following table approximates counterparty
credit quality and exposure for AEP based on netting across AEP entities,
commodities and instruments:
TABLE 4
Futures,
Forward and
Counterparty Swap
Credit Quality: Contracts Options Total
(in millions)
AAA/Exchanges $ 12 $33 $ 45
AA 302 19 321
A 338 17 355
BBB 515 161 676
Below
Investment
Grade 77 11 88
Total $ 1,244 $241 $1,485
The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.
Merchant Plant Owned Assets Production and Hedging Information
Table 5 provides information on 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.
TABLE 5
Merchant Plant-Owned Assets Hedging Information
Estimated Next Three Years
As of March 31, 2003
2003 2004 2005
Estimated Plant Output Hedged (a) 93% 88% 83%
(a) Estimated Plant Output Hedged - Represents the portion of
megawatt-hours of future generation production for which AEP has sales
commitments to customers.
VaR Associated with Energy Trading Contracts
AEP uses a risk measurement model which calculates Value at Risk (VaR) to
measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is
based on the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes 95% confidence level, a one-day
holding period and a one-tailed distribution. Based on this VaR analysis, at
March 31, 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 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
-------
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
and year-to-date:
AEP VaR Model
March 31,September 30, 2002 or the years ended December 31, 2003 2002, End High Average Low End High Average Low2001 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)
AEP $7 $19AEGCo $ 7 $5 $5 $24 $12 $41.1 $ 1.0
APCo 1 3 2 1 1 4 1 -20.1 18.7
CSPCo 1 2 1 1 1 3 1 -8.1 7.5
I&M 1 2 1 1 1 3 1 -516.1 481.4
KPCo - 1 - - - 1 - -
OPCo 1 2 1 1 1 4 1 -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 High VaRconsensus 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
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 VaR2003 for the quarter.
The AEP VaR model results are adjusted using standard statistical treatments to
calculate the Committeeadoptions of Chief Risk Officers (CCRO) VaR reporting metrics
listed below. The adjustments are made to take the AEP model results from a
one-day holding period to the ten-day holding period, from a one-tailed result
to a two-tailed resultSFAS 143 and from the 95% confidence level to the 99% confidence
level. The AEP VaR model's performance has not been evaluated for its accuracy
at calculating VaR using the CCRO VaR Metrics assumptions.EITF 02-3 (no effect on AEGCo
or PSO):
Committee of Chief Risk Officers (CCRO) VaR Metrics
Average
End of Q1 2003 for Q1 2003 High for Q1 2003 Low for Q1 2003SFAS 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)
95% Confidence Level, Ten-Day
Holding Period, Two-Tailed $26 $28 $71 $17
99% Confidence Level, One-Day
Holding Period, Two-Tailed $11 $12 $30
APCo $128.3 $ 780.3 $ (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 - -
AEP utilizesSFAS 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 VaR modelderivative
and the requirements for contracts to measurequalify 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 rate market risk exposure.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 interest rate VaR model is basedinitial
recognition and initial measurement provisions of FIN 45 are effective
on a Monte Carlo simulationprospective 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 a 95%
confidence level, a one year holdingthe 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 a one-tailed distribution.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 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 $1,047
million at March 31, 2003 and $527 millionunder-recovery balance at
December 31, 2002. AEP2001 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 not
expectresult 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 liquidate its entire debt portfoliothe 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
year holdingexception. 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 therefore a near term change in interestprior 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 materially affectbe 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 consolidated financial position.
AEGCothe 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 exposedexpected to riskhave 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 interestApril 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 short-termRegional Through and long-term borrowingsOut 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 finance operations since financingvalue 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 agreements.
AEP is exposed to risk from changescustomers during the outage. Therefore, we were
subject to fluctuations in the market prices of coalelectricity and
natural gas
usedpurchased replacement energy.
In April 2003, both units of I&M's Cook Plant were taken offline due 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 eliminatedan 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 implementationfish intrusion, Cook Plant Unit 1 returned to
service in May and Unit 2 returned to service in June following
completion of customer choicea scheduled refueling outage.
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo,
I&M, and OPCo
As discussed in Ohio (effective January 1, 2001 for CSPCo and OPCo) andNote 9 of the Combined Notes to Financial Statements in
the ERCOT area2002 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 Texas (effective January 1, 2002states 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 TCC and TNC) or frozenthe
Southern District of Ohio. A separate lawsuit initiated by settlement agreements in Michigan and West Virginia or capped in Indiana. Tocertain
special interest groups was consolidated with the extent the fuel supplyFederal 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 these states is not under
fixed price long-term contracts AEP is subject to market price risk. AEP
continues toan emissions increase, permitting requirements might
be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginiatriggered and the SPP areaplant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of Texas.
AEP employs physical forward purchasedegraded
equipment or failed components, or other repairs needed for the
reliable, safe and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contractsefficient operation of the plant. The Clean Air Act
authorizes civil penalties of up to offset price risk where appropriate. AEP engages in risk management of
electricity, gas and$27,500 per day per violation at
each generating unit ($25,000 per day prior to a lesser degree other commodities and as a result AEP is
subject to price risk. The amount of risk taken byJanuary 30, 1997). In
2001, the staff is controlled by
risk management operations and AEP's Chief Risk Officer and his staff. When the
risk from energy tradingDistrict Court ruled claims for civil penalties based on
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.
CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures. Our chief
executive officer and our chief financial officer, after
evaluating the effectiveness of "disclosure controls and
procedures" (as defined in the Securities Exchange Act of 1934
Rules 13a-14(c) and 15d-14(c)) as of a date (the "Evaluation
Date") within 90 daysthat 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 quarterly
report,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 concludedfiled 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 Evaluation Date, ourSEC 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 were adequate andhave been designed to
ensure that (a) material information relating to us and ourAEP, including its
consolidated subsidiaries, would beis made known to themAEP's management, including
these officers, by othersother employees of AEP and its subsidiaries, and (b) this
information is recorded, processed, summarized, evaluated and reported, as
applicable, within those entities.
(b) Changesthe time periods specified in internal controls. There were no significant changes
in our internalthe SEC's rules and forms.
AEP's controls or to our knowledge, in other factorsand procedures can only provide reasonable, not absolute,
assurance that could significantly affect ourthe above objectives have been met.
As of September 30, 2003, these officers concluded that the disclosure
controls and procedures subsequentin 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 Evaluation Date.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 99.131.1 - 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 99.232.2 - 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 March 31,September 30, 2003.
Company Reporting Date of Report Item Reported
AEP February 25, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Financial Statements
and Exhibits
AEP February 26, 2003 Item 7. Financial Statements
And Exhibits
Item 9. Regulation FD
Disclosure
AEP February 27,
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
AEP March 14, 2003 Item 5. Other Events and
Regulation FD Disclosures
Item 7. Financial Statements
And Exhibits
CSPCo and OPCo February 4, 2003 Item 5. Other Events and
Regulation FD Disclosure
SignaturesSignature
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 signaturessignature 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/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto
Geoffrey S. Chatas-----------------------
Joseph M. Buonaiuto
Treasurer
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/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto
Geoffrey S. Chatas-----------------------
Joseph M. Buonaiuto
Treasurer
Controller and
Chief Accounting Officer
Date: May 14,November 12, 2003
CERTIFICATIONS
I, E. Linn Draper, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of:
American Electric Power Company, Inc.
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company;
2. Based on my knowledge, this quarterly report does not
contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements
made, in light of the circumstances under which such
statements were made, not misleading with respect to the
period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the
"Evaluation Date"); and
c) presented in this quarterly report our conclusions about
the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6.
The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Dated: May 14, 2003 By: /s/ E. Linn Draper, Jr.
E. Linn Draper, Jr.
Chief Executive Officer
I, Susan Tomasky, certify that:
1. I have reviewed this quarterly report on Form 10-Q of:
American Electric Power Company, Inc.
AEP Generating Company
AEP Texas Central Company
AEP Texas North Company
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company;
2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6.
The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: May 14, 2003 By: /s/ Susan Tomasky
Susan Tomasky
Chief Financial Officer