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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrant, State of Incorporation,
 
I.R.S. Employer
File Number
 
Address of Principal Executive Offices, and Telephone Number
 
Identification No.
         
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
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 (An Oklahoma Corporation)
 
73-0410895
1-3146
 
SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
 
72-0323455
         
All Registrants
 
1 Riverside Plaza, Columbus, Ohio 43215-2373
   
   
Telephone (614) 716-1000
   

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 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.





   
Number of Shares of Common Stock Outstanding at April 29, 2005
 
       
American Electric Power Company, Inc.
   
384,020,319
 
AEP Generating Company
   
1,000
 
AEP Texas Central Company
   
2,211,678
 
AEP Texas North Company
   
5,488,560
 
Appalachian Power Company
   
13,499,500
 
Columbus Southern Power Company
   
16,410,426
 
Indiana Michigan Power Company
   
1,400,000
 
Kentucky Power Company
   
1,009,000
 
Ohio Power Company
   
27,952,473
 
Public Service Company of Oklahoma
   
9,013,000
 
Southwestern Electric Power Company
   
7,536,640
 


 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 2005

 
 
 
Glossary of Terms
 
 
Forward-Looking Information
 
 
Part I. FINANCIAL INFORMATION
 
   
Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
 
       
   
American Electric Power Company, Inc. and Subsidiary Companies:
     
Management’s Financial Discussion and Analysis of Results of Operations
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
     
Notes to Consolidated Financial Statements
 
       
   
AEP Generating Company:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Financial Statements
 
       
   
AEP Texas Central Company and Subsidiary:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
       
   
AEP Texas North Company:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Financial Statements
 
       
   
Appalachian Power Company and Subsidiaries:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
       
   
Columbus Southern Power Company and Subsidiaries:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
       
   
Indiana Michigan Power Company and Subsidiaries:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
       
   
Kentucky Power Company:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Financial Statements
 
       
   
Ohio Power Company Consolidated:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
 
   
Public Service Company of Oklahoma:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Financial Statements
 
       
   
Southwestern Electric Power Company Consolidated:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Consolidated Financial Statements
 
       
   
Notes to Financial Statements of Registrant Subsidiaries
 
       
   
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
       
Item 4.
 
Controls and Procedures
 
       
Part II. OTHER INFORMATION
 
Item 1.
 
Legal Proceedings
 
Item 2.
 
Unregistered Sales of Equity Securities and Use of Proceeds
 
Item 5.
 
Other Information
 
Item 6.
 
Exhibits
 
           
Exhibits:
 
           
Exhibit 4 (a)
 
           
Exhibit 10 (a)
 
           
Exhibit 10 (b)
 
           
Exhibit 12
 
           
Exhibit 31(a)
 
           
Exhibit 31(b)
 
           
Exhibit 31(c)
 
           
Exhibit 31(d)
 
           
Exhibit 32(a)
 
           
Exhibit 32(b)
 
       
 
SIGNATURE
 

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.







GLOSSARY OF TERMS
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

 
Term
 
 
      Meaning

AEGCo
 
      AEP Generating Company, an electric utility subsidiary of AEP.
AEP or Parent
 
American Electric Power Company, Inc.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for
  affiliated domestic electric utility companies.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
AEPES
 
AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System
 
The American Electric Power System, an integrated electric utility system, owned and operated by AEP’s
  electric utility subsidiaries.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional
  services to AEP and its subsidiaries.
AEP System Power Pool or AEP
  Power Pool
 
Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and
  resultant wholesale off-system sales of the member companies.
AEP West companies
 
PSO, SWEPCo, TCC and TNC.
ALJ
 
Administrative Law Judge.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
ARO
 
Asset Retirement Obligations.
CAA
 
The Clean Air Act.
Cook Plant
 
The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
COLI
 
Corporate owned, life insurance program.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of
  Central and South West Corporation was changed to AEP Utilities, Inc.).
DETM
 
      Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE
 
      United States Department of Energy.
ECAR
 
East Central Area Reliability Council.
EITF
 
The Financial Accounting Standards Board’s Emerging Issues Task Force.
ERCOT
 
The Electric Reliability Council of Texas.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
      United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FIN 46
 
FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.”
GAAP
 
Generally Accepted Accounting Principles.
HPL
 
Houston Pipeline Company.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPP
 
Independent Power Producers.
IURC
 
Indiana Utility Regulatory Commission.
JMG
 
JMG Funding LP.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
KWH
 
Kilowatthour.
LIG
 
Louisiana Intrastate Gas, a former AEP subsidiary.
ME SWEPCo
 
Mutual Energy SWEPCo L.P., a Texas retail electric provider.
MLR
 
Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP System’s Nonutility Money Pool.
OATT
 
Open Access Transmission Tariff.
OCC
 
Oklahoma Corporation Commission.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OTC
 
Over the counter.
PJM
 
Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utility Commission of Ohio
PUCT
 
The Public Utility Commission of Texas.
PUHCA
 
Public Utility Holding Company Act.
PURPA
 
The Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries
 
AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
  TCC and TNC.
REP
 
      Texas Retail Electric Provider.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by
  AEGCo and I&M.
RTO
 
Regional Transmission Organization.
S&P
 
Standard and Poor’s.
SEC
 
United States Securities and Exchange Commission.
SECA
 
Seams Elimination Cost Allocation.
SFAS
 
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 109
 
Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.
SFAS 133
 
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
  Activities.
SNF
 
Spent Nuclear Fuel.
SPP
 
Southwest Power Pool.
STP
 
South Texas Project Nuclear Generating Plant, owned 25.2% by TCC.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor
 
Maturity of a contract.
Texas Restructuring   Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding
 
A filing to be made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other
  true-up items and the recovery of such amounts.
TVA
 
Tennessee Valley Authority.
Utility Money Pool
 
AEP System’s Utility Money Pool.
VaR
 
Value at Risk, a method to quantify risk exposure.
Virginia SCC
 
Virginia State Corporation Commission.
Zimmer Plant
 
William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by CSPCo.


 



FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of 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:

·
Electric load and customer growth.
·
Weather conditions, including storms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness of fuel suppliers and transporters.
·
Availability of generating capacity and the performance of our generating plants.
·
The ability to recover regulatory assets and stranded costs in connection with deregulation.
·
The ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon and other substances.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for new investments, transmission service and environmental compliance).
·
Oversight and/or investigation of the energy sector or its participants.
·
Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp.).
·
Our ability to constrain operation and maintenance costs.
·
Our ability to sell assets at acceptable prices and other acceptable terms, including rights to share in earnings derived from the assets subsequent to their sale.
·
The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·
Inflationary trends.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·
Changes in the creditworthiness and number of participants in the energy trading market.
·
Changes in the financial markets, particularly those affecting the availability of capital and our ability to refinance existing debt at attractive rates.
·
Actions of rating agencies, including changes in the ratings of debt.
·
Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
·
Changes in utility regulation, including membership and integration into regional transmission structures.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The performance of our pension and other postretirement benefit plans.
·
Prices for power that we generate and sell at wholesale.
·
Changes in technology and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.

 



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Utility Operations Segment Results
Net income from Utility Operations was $353 million for the first quarter of 2005, representing an increase of $49 million. This increase over first quarter 2004 was partially due to payments totaling $115 million received in March 2005 from Centrica related to the earnings sharing agreement as stipulated in the purchase and sale agreement from the sale of our Texas Retail Electric Providers (REPs) in 2002. The payments received related to 2002, 2003 and 2004. We expect to receive and recognize additional earnings sharing payments in 2006 and 2007 related to 2005 and 2006 activity, respectively. The earnings sharing payments for 2005 and 2006 are capped at $70 million and $20 million, respectively. However, all payments are contingent on the operating results of Centrica. Therefore, receipt of payments for future activity is not assured.

Additional increases in first quarter 2005 included $45 million related to regulatory assets established by our Ohio companies for fulfilling our Provider of Last Resort obligations, for which the PUCO authorized recovery in its approval of our Rate Stabilization Plans in January 2005.

Partially offsetting these two favorable items is an unfavorable variance of $50 million related to higher delivered fuel costs, as further discussed below in the “Fuel Costs” section, and $31 million related to reduced margins on transmission revenues.

Divestiture Proceeds
We sold a 98% share of our Houston Pipe Line Company (HPL) in January 2005 for approximately $1 billion. In March 2005, we used the cash proceeds to repurchase 12.5 million shares of our common stock in a share repurchase transaction at an initial share price of $34.63 per share and on April 15, 2005 we redeemed $550 million of our senior notes. These activities continue to emphasize our focus on strengthening our balance sheet and reducing debt at the parent company level.

Environmental
On March 10, 2005, the Federal EPA released the Clean Air Interstate Rule (CAIR), which further limits emissions of sulfur dioxide and nitrogen oxides and sets new limits on power plant emissions associated with soot, smog and acid rain in the eastern half of the United States. It is likely that we will add nine new flue gas desulphurization units (FGDs) and three selective catalytic reactors (SCRs) to our eastern fleet in order to meet existing requirements as well as the tighter requirements of the new rule. FGDs currently are installed and operating at four east and two west plants and are under construction at three east plants.

On March 15, 2005, the Federal EPA released its final rule on mercury emissions from power plants, which would allow a cap-and-trade system. The cap-and-trade system creates incentives for continued development and testing of promising mercury control technologies and, by making the mercury emissions a tradable commodity, the new system provides a strong motivation to make early emission reductions and for continuous improvements in control technologies. The installation of SCRs and FGDs at a facility have the co-benefit of mercury capture.

We are currently developing an estimate of additional costs to comply with the newly issued rules. Accordingly, we have not yet changed our previously announced plans related to capital investment amounts of $3.7 billion through 2010 and $5 billion through 2020. We continue to support our investment program through the use of free cash flow and rate increases and therefore, do not anticipate material incremental leveraging.

Texas Regulatory Activity

Stranded Cost Recovery
In February 2005, TCC filed with the PUCT requesting a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to the closing of the sale of TCC’s ownership interest in Oklaunion. The asset sales pending are our Oklaunion and STP interests. The sale of TCC’s interest in STP should be completed in the first half of 2005, subject to obtaining the necessary regulatory approvals. There are likely to be delays in resolving rights of first refusal issues and related litigation with a third party affecting Oklaunion.

TCC Rate Case
Hearings were held on the affiliated transactions remand issue in March 2005. The PUCT deferred ruling on the allowable amount of TCC affiliate transactions. See the “Significant Matters - TCC Rate Case” section below for further discussion.

Fuel Costs
Market prices for coal, natural gas and oil increased dramatically during 2004. These increasing fuel costs are the result of increasing worldwide demand, supply uncertainty, and transportation constraints, as well as other market factors. We manage price and performance risk, particularly for coal, through a portfolio of contracts of varying durations and other fuel procurement and management activities. We have fuel recovery mechanisms for about 50% of our fuel costs in our various jurisdictions. Additionally, about 20% of our fuel is used for off-system sales where prices we receive for our power sales should recover our cost of fuel. Accordingly, approximately 70% of fuel cost increases are recovered. The remaining 30% of our fuel costs relate to Ohio and West Virginia customers, where we do not have a fuel cost recovery mechanism. During the first quarter of 2005, higher delivered coal costs reduced gross margins by approximately $50 million. We currently have 100% and 88% of our projected coal needs committed for 2005 and 2006, respectively.

New Technology Plant
Our plans to construct synthetic-gas-fired plant(s) in the next five to six years utilizing integrated gasification combined cycle (IGCC) technology continued to progress. During the first quarter of 2005, three important regulatory filings were made.

On February 10, 2005, we asked PJM to evaluate transmission interconnection feasibility for three potential sites currently under consideration for the plant(s). Those sites include Mason County, West Virginia, Meigs County, Ohio, and Lewis County, Kentucky. The filing with PJM will begin feasibility studies to determine the transmission network upgrades and estimated cost needed at each site to connect a new plant to the existing transmission grid.

On March 15, 2005, APCo notified the Public Service Commission of West Virginia of its intent to file for a Certificate of Public Convenience and Necessity, reflecting APCo’s need for new generating capacity to meet the growing demand for electricity and to ensure a reliable supply of electricity for its customers.

On March 18, 2005, CSPCo and OPCo filed an application with the PUCO seeking authority to recover costs related to the construction and operation of an IGCC plant. This filing followed a suggestion by the PUCO in its January 2005 Rate Stabilization Plan order that CSPCo and OPCo proceed with this construction.

Additional Information
For additional information on our strategic outlook, see “Management’s Financial Discussion and Analysis of Results of Operations,” including “Business Strategy,” in our 2004 Annual Report. Also see the remainder of our “Management’s Financial Discussion and Analysis of Results of Operations” in this Form 10-Q, along with the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their major activities are:

·
Utility Operations:
Domestic generation of electricity for sale to retail and wholesale customers.
Domestic electricity transmission and distribution.

·
Investments-Gas Operations (a)
Gas pipeline and storage services.
Gas marketing and risk management activities.

·
Investments-UK Operations (b)
Generation of electricity in the U.K. for sale to wholesale customers.
Coal procurement and transportation to our plants.
   
·
Investments-Other: (c)
Bulk commodity barging operations, wind farms, independent power producers and other energy
 
supply related businesses.

(a)
LIG Pipeline Company and its subsidiaries, including Jefferson Island Storage & Hub LLC, were classified as discontinued operations during 2003 and were sold during 2004. We sold a 98% interest in HPL during the first quarter of 2005.
(b)
UK Operations were classified as discontinued operations during 2003 and were sold during the third quarter of 2004.
(c)
Four independent power producers were sold during the third and fourth quarter of 2004.

AEP Consolidated Results

Our consolidated Net Income for the three-month periods ended March 31, 2005 and 2004 was as follows (Earnings and Weighted Average Shares Outstanding in millions):

   
2005
 
2004
 
   
Earnings
 
EPS
 
Earnings
 
EPS
 
Utility Operations
 
$
353
 
$
0.90
 
$
304
 
$
0.77
 
Investments - Gas Operations
   
10
   
0.03
   
(10
)
 
(0.03
)
Investments - Other
   
5
   
0.01
   
4
   
0.01
 
All Other (a)
   
(14
)
 
(0.04
)
 
(9
)
 
(0.02
)
Income Before Discontinued Operations
   
354
   
0.90
   
289
   
0.73
 
                           
Investments - Gas Operations
   
-
   
-
   
(1
)
 
-
 
Investments - UK Operations
   
(5
)
 
(0.01
)
 
(12
)
 
(0.04
)
Investments - Other
   
6
   
0.01
   
6
   
0.02
 
Discontinued Operations, Net of Tax
   
1
   
-
   
(7
)
 
(0.02
)
                           
Net Income
 
$
355
 
$
0.90
 
$
282
 
$
0.71
 
                           
Weighted Average Shares Outstanding
         
393
         
395
 

(a) All Other includes the parent company’s interest income and expense, as well as other nonallocated costs.

First Quarter of 2005 Compared to First Quarter of 2004

Income Before Discontinued Operations increased $65 million to $354 million in the first quarter of 2005 compared to the first quarter of 2004.

For the first quarter of 2005, our Utility Operations earnings increased $49 million from the previous year driven primarily by the Centrica earnings sharing and Ohio carrying cost accruals somewhat offset by higher fuel costs and milder weather in the winter months of 2005.

Earnings from our Gas Operations increased $20 million from the previous year reflecting favorable results for one month of HPL’s operations in 2005 rather than three months in the prior year due to the sale of the HPL assets in January 2005, which resulted in decreased operations, maintenance and depreciation expenses as well as decreased interest charges.

The loss from our All Other grouping, primarily representing parent company income and expenses, increased $5 million in 2005. This increase is primarily due to lower interest income and lower guarantee fees received in the current period.

Average shares outstanding decreased to 393 million in 2005 from 395 in 2004 primarily due to the common stock share repurchase program approved by our Board of Directors in February 2005.

Our results of operations by operating segment are discussed below.

Utility Operations

   
Three Months Ended
March 31,
 
   
2005
 
2004
 
   
(in millions)
 
Revenues
 
$
2,614
 
$
2,602
 
Fuel and Purchased Power
   
905
   
779
 
Gross Margin
   
1,709
   
1,823
 
Depreciation and Amortization
   
318
   
310
 
Other Operating Expenses
   
871
   
888
 
Operating Income
   
520
   
625
 
Other Income (Expense), Net
   
148
   
9
 
Interest Expenses and Preferred Stock Dividend Requirements
   
144
   
166
 
Income Taxes
   
171
   
164
 
Income Before Discontinued Operations
 
$
353
 
$
304
 
 

 
Summary of Selected Sales Data
For Utility Operations
For the Three Months Ended March 31, 2005 and 2004

   
2005
 
2004
 
Energy Summary
 
(in millions of KWH)
 
Retail:
         
Residential
   
13,224
   
13,427
 
Commercial
   
8,732
   
8,779
 
Industrial
   
12,774
   
12,273
 
Miscellaneous
   
645
   
743
 
Subtotal
   
35,375
   
35,222
 
Texas Retail and Other
   
228
   
224
 
Total
   
35,603
   
35,446
 
               
Wholesale
   
12,635
   
13,851
 
               
Texas Wires Delivery
   
5,519
   
5,490
 
 

 
   
2005
 
2004
 
Weather Summary
 
(in degree days)
 
Eastern Region
         
Actual - Heating
   
1,774
   
1,864
 
Normal - Heating (a)
   
1,811
   
1,806
 
               
Actual - Cooling
   
-
   
3
 
Normal - Cooling (a)
   
3
   
3
 
               
Western Region (b)
             
Actual - Heating
   
769
   
883
 
Normal - Heating (a)
   
973
   
978
 
               
Actual - Cooling
   
20
   
30
 
Normal - Cooling (a) 
   
18
   
17
 

(a) Normal Heating/Cooling represents the 30-year average of degree days.
 
(b) Western Region statistics represent PSO/SWEPCo customer base only.

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005
Income Before Discontinued Operations
(in millions)

First Quarter of 2004
       
$
304
 
               
Changes in Gross Margin:
             
Retail Margins
   
(60
)
     
Texas Supply
   
(20
)
     
Transmission Revenues
   
(31
)
     
Off-system Sales
   
(7
)
     
Other Revenues
   
4
       
           
(114
)
               
Changes in Operating Expenses And Other:
             
Maintenance and Other Operation
   
21
       
Depreciation and Amortization
   
(8
)
     
Taxes Other Than Income Taxes
   
(4
)
     
Other Income (Expense), Net
   
139
       
Interest Expenses
   
22
       
           
170
 
               
Income Taxes
         
(7
)
               
First Quarter of 2005
       
$
353
 

Income from Utility Operations increased $49 million to $353 million in 2005. The key drivers of the increase were a $139 million increase in other income (expense), net and a $31 million net decrease in operating expenses and other partially offset by a $114 million decrease in gross margin and a $7 million increase in income tax expense.

The major components of our change in gross margin, defined as utility revenues net of related fuel and purchased power, were as follows:

·
Overall retail margins in our utility business were $60 million lower than last year. The primary driver of this decrease was higher delivered fuel costs of approximately $50 million, of which $25 million relates to our Ohio jurisdiction, $16 million relates to APCo and $6 million relates to I&M.
·
Our Texas supply business had a $20 million decrease in gross margin as a result of decreased generation due to the sale of a majority of our Texas generation assets in the third quarter of 2004.
·
Margins from transmission revenues decreased $31 million primarily due to the loss of through and out rates as mandated by the FERC.
·
Margins from off-system sales for 2005 were $7 million lower than 2004 primarily due to lower optimization activity of $31 million partially offset by a $24 million increase in revenues due to a 5% increase in sales volumes.

Utility Operating Expenses and Other changed between years as follows:
 
·
Maintenance and Other Operation expenses decreased $21 million. Overall, the decrease is due to timing and different spending patterns experienced in the first quarter of 2005 as compared to the same period in 2004. Additionally, benefit expenses were lower by $23 million primarily due to the cancellation of our corporate-owned life insurance (COLI) policies in 2005. These favorable variances were partially offset by storm expenses of $19 million related to a major ice storm in January 2005, primarily in our Indiana and Ohio jurisdictions.
·
Other Income (Expense), Net increased $139 million primarily due to the following:
           ·
$112 million related to the $115 million payment received in March 2005 for the Centrica earnings sharing, which represents receipt of revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase and sale agreement from the sale of our REPs in 2002. Agreement was reached with Centrica in March 2005 resolving disputes on how such amounts are to be calculated.
           ·
$26 million related to the accrual of carrying costs on environmental and RTO expenses by our Ohio companies related to the Rate Stabilization Plans.
 ·
Interest Expenses decreased $22 million due to the refinancing of higher coupon debt and the retirement of debt in 2004 and in the first quarter of 2005.
 
$112 million related to the $115 million payment received in March 2005 for the Centrica earnings sharing, which represents receipt of revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase and sale agreement from the sale of our REPs in 2002. Agreement was reached with Centrica in March 2005 resolving disputes on how such amounts are to be calculated.
 
$26 million related to the accrual of carrying costs on environmental and RTO expenses by our Ohio companies related to the Rate Stabilization Plans.
 
See “Income Taxes” section below for discussion of fluctuations related to income taxes.

Investments-Gas Operations

First Quarter of 2005 Compared to First Quarter of 2004

Our $10 million net income from Gas Operations before discontinued operations compares with a $10 million loss recorded in the first quarter of 2004. Due to the sale of the HPL assets in January 2005, current year results include only one month of HPL’s operations compared to three months of HPL’s operations in the prior year. Approximately $14 million of the $20 million variance relates to a decrease in operation, maintenance and depreciation expenses and $5 million relates to a decrease in interest charges.

Investments - - UK Operations

First Quarter of 2005 Compared to First Quarter of 2004

Losses from our Investments - UK Operations segment (all classified as Discontinued Operations) were $5 million in 2005 as compared to $12 million in 2004 due to the sale of substantially all operations and assets within our Investments - UK Operations segment in July 2004. The current period amount represents purchase price true-up adjustments made during the first quarter of 2005 related to the sale in 2004.


Investments - - Other

First Quarter of 2005 Compared to First Quarter of 2004

Income before discontinued operations from our Investments - Other segment increased by $1 million in 2005 primarily due to the following:

·
A $5 million increase at CSW Energy Services related to a current year gain due to a working capital true-up of the Numanco sale that occurred in November 2004 and a release of product liability and litigation reserves related to our Total Electric Vehicle investment due to the resolution of all open litigation as of March 31, 2005.
·
A $3 million increase at AEP Communications due to debt being moved to the parent in October 2004.
·
A $3 million increase at AEP Investments due to the investment write-down of PHPK Technologies, Inc. in 2004 of $1 million and favorable earnings from Pac Hydro of $2 million in 2005.
·
A $3 million increase at CSW International related to tax reserve adjustments in March 2005.
·
A $13 million decrease at AEP Resources related to a $2 million favorable judgment on an Australian tax issue received in 2004, a $4 million entry in 2004 related to capitalized fuel during construction of the Dow Plant, $3 million of losses related to the Dow plant in 2005 and a tax adjustment of $3 million booked in 2005.
·
A $3 million decrease at our IPPs resulting from the sale of four of our IPPs in mid-2004.

All Other

First Quarter of 2005 Compared to First Quarter of 2004

Our parent company’s loss for the first quarter of 2005 increased $5 million in comparison to the first quarter of 2004 due to lower interest income of $2 million and lower guarantee fees received of $1 million.

Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were 32.7% and 35.9%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, energy production credits, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences including COLI and lower state income taxes.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

Capitalization ($ in millions)

   
March 31, 2005
 
December 31, 2004
 
Common Shareholders’ Equity
 
$
8,268
   
39.9
%
$
8,515
   
40.6
%
Cumulative Preferred Stock
   
61
   
0.3
   
61
   
0.3
 
Cumulative Preferred Stock (Subject to Mandatory Redemption)
   
-
   
-
   
66
   
0.3
 
Long-term Debt, including amounts due within one year
   
12,359
   
59.7
   
12,287
   
58.7
 
Short-term Debt
   
19
   
0.1
   
23
   
0.1
 
                           
Total Capitalization
 
$
20,707
   
100.0
%
$
20,952
   
100.0
%

In March 2005, we repurchased 12.5 million shares of our outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share. The 12.5 million shares repurchased under the program are subject to a future contingent purchase price adjustment based on the actual purchase prices paid for the common stock during the program period. Based on this adjustment, an asset of $2 million is reflected in Accounts Receivable on our Consolidated Balance Sheets as of March 31, 2005 due to the fact that the actual stock purchase prices were less than our initial payment.

As a consequence of the capital changes during the first quarter of 2005, our ratio of debt to total capital increased from 59.1% to 59.8% (preferred stock subject to mandatory redemption is included in the debt component of the ratio).

In April 2005, we reduced our ratio of debt to total capital through the redemption of $550 million of parent company senior notes.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability. We are committed to preserving an adequate liquidity position.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. We had an available liquidity position, at March 31, 2005, of approximately $4 billion as illustrated in the table below.

 
   
Amount
   
Maturity
 
   
(in millions)
       
Commercial Paper Backup:
           
 
Revolving Credit Facility
 
$
1,000
   
May 2007
 
 
Revolving Credit Facility
   
1,500
   
March 2010
 
Letter of Credit Facility
   
200
   
September 2006
 
Total
   
2,700
       
Cash and Cash Equivalents
   
1,261
       
Total Liquidity Sources
   
3,961
       
Less: AEP Commercial Paper Outstanding
   
-
(a)
     
   
Letters of Credit Outstanding
   
50
       
               
Net Available Liquidity at March 31, 2005
 
$
3,911
       
 
(a)
Amount does not include JMG commercial paper outstanding in the amount of $19 million. This commercial paper is specifically associated with the Gavin scrubber and does not reduce AEP’s available liquidity. The JMG commercial paper is supported by a separate letter of credit facility not included above.


Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At March 31, 2005, this percentage was 55%. Nonperformance of these covenants could result in an event of default under these credit agreements. At March 31, 2005, we complied with the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the amounts outstanding thereunder payable.

Our revolving credit facilities generally prohibit new borrowings if we experience a material adverse change in our business or operations. We may, however, make new borrowings under these facilities if we experience a material adverse change so long as the proceeds of such borrowings are used to repay outstanding commercial paper. Under the $1.5 billion revolving credit facility, which matures in March 2010, we may borrow despite a material adverse change if our ratings are BBB (or better) from Standard and Poor’s (S&P), and Baa2 (or better) from Moody’s at any time during the facility’s term.

Under an SEC order, we and our utility subsidiaries cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% (25% for TCC) of its capital. In addition, this order restricts us and our utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. At March 31, 2005, we were in compliance with this order.

Nonutility Money Pool borrowings, Utility Money Pool borrowings and external borrowings may not exceed SEC or state commission authorized limits. At March 31, 2005, we had not exceeded the SEC or state commission authorized limits.

Credit Ratings

AEP’s ratings have not been adjusted by any rating agency during 2005 and AEP, Inc. is currently on a “positive” outlook by Moody’s.

Our current ratings by the major agencies are as follows:

 
Moody’s
 
S&P
 
Fitch
           
Short-term Debt
P-3
 
A-2
 
F-2
Senior Unsecured Debt
Baa3
 
BBB
 
BBB

If AEP or any of its rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease. If we receive a downgrade in our credit ratings by one of the nationally recognized rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow  

Our cash flows are a major factor in managing and maintaining our liquidity strength.

   
Three Months Ended
March 31,
 
   
2005
 
2004
 
   
(in millions)
 
Cash and cash equivalents at beginning of period
 
$
320
 
$
778
 
Cash flows from (used for):
             
Operating activities
   
673
   
897
 
Investing activities
   
788
   
(186
)
Financing activities
   
(520
)
 
(576
)
Net increase in cash and cash equivalents
   
941
   
135
 
Cash and cash equivalents at end of period
 
$
1,261
 
$
913
 
Other temporary cash investments
 
$
181
 
$
340
 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provide necessary working capital and help us meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of our other subsidiaries that are not participants in the Nonutility Money Pool. As of March 31, 2005, we had credit facilities totaling $2.5 billion to support our commercial paper program. At March 31, 2005, we had no outstanding short-term borrowings supported by the revolving credit facilities. JMG had commercial paper outstanding in the amount of $19 million. This commercial paper is specifically associated with the Gavin scrubber and is not supported by our credit facilities. The maximum amount of commercial paper outstanding during the quarter ended March 31, 2005 was $25 million. The weighted-average interest rate for our commercial paper during the first quarter of 2005 was 2.59%.

We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding alternatives are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements.

In addition to our cash and cash equivalents we have other temporary cash investments on hand that factor in managing and maintaining our liquidity.

Operating Activities

   
Three Months Ended
March 31,
 
   
2005
 
2004
 
   
(in millions)
 
Net Income
 
$
355
 
$
282
 
Plus: Loss From Discontinued Operations
   
(1
)
 
7
 
Income from Continuing Operations
   
354
   
289
 
Noncash Items Included in Earnings
   
243
   
222
 
Changes in Assets and Liabilities
   
76
   
386
 
Net Cash Flows From Operating Activities
 
$
673
 
$
897
 

The key drivers of the decrease in cash from operations for the first quarter of 2005 are the pension trust contribution of $102 million and the gain on sale of assets of $115 million, $112 million of which relates to the sale of our Texas REPs to Centrica.

2005 Operating Cash Flow

Our net cash flows from operating activities were $673 million for the first quarter of 2005. We produced income from continuing operations of $354 million during the period. Income from continuing operations for the period included noncash expense items of $318 million for depreciation, amortization, accretion and deferred taxes. In addition, there is a current period favorable impact for a net $27 million balance sheet change for risk management contracts that are marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. We made a $102 million contribution to our pension trust fund. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a decrease in the balance of fuel, materials and supplies of $64 million primarily due to reduced gas inventory associated with the sale of HPL and an increase in the balance of accrued taxes of $245 million. Accrued taxes increased because our consolidated tax group was not required to make an estimated payment during the first quarter of 2005.

2004 Operating Cash Flow

Our net cash flows from operating activities were $897 million for the first quarter of 2004. We produced income from continuing operations of $289 million during the period. Income from continuing operations for the period included noncash items of $374 million for depreciation, amortization, accretion and deferred taxes. There was a current period unfavorable impact for a net $59 million balance sheet change for risk management contracts that were marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The most significant changes in other activity in the asset and liability accounts are an increase in accrued taxes of $189 million and net changes in accounts receivable and accounts payable of $88 million.



Investing Activities

   
Three Months Ended
March 31,
 
   
2005
 
2004
 
   
(in millions)
 
Construction Expenditures
 
$
(465
)
$
(305
)
Change in Other Temporary Cash Investments, Net
   
94
   
64
 
Proceeds from Sales of Assets
   
1,157
   
40
 
Other
   
2
   
15
 
Net Cash Flows From (Used for) Investing Activities
 
$
788
 
$
(186
)

Our cash flows from investing activities were $788 million in 2005 primarily due to proceeds from the sale of HPL in 2005. We used the cash from asset sales to repurchase common stock. Our construction expenditures include environmental, transmission and distribution investments as we had planned. Our remaining construction expenditures for 2005 are estimated to be approximately $2.2 billion.

Our cash flows used for investing activities were $186 million in 2004 primarily due to construction expenditures.

Financing Activities

   
Three Months Ended
March 31,
 
   
2005
 
2004
 
   
(in millions)
 
Issuances of Common Stock
 
$
17
 
$
10
 
Repurchase of Common Stock
   
(434
)
 
-
 
Issuances/Retirements of Debt, net
   
101
   
(444
)
Retirement of Preferred Stock
   
(66
)
 
(4
)
Dividends Paid
   
(138
)
 
(138
)
Net Cash Flows Used for Financing Activities
 
$
(520
)
$
(576
)

Our cash flows used for financing activities in 2005 were $520 million. During the first quarter of 2005, we repurchased common stock using the proceeds from the sale of HPL. Our subsidiaries retired $66 million of cumulative preferred stock. See Note 10 for a complete discussion of debt issuances and retirements.

Our cash flows used for financing activities were $576 million in 2004. During the first quarter of 2004, we retired debt using cash from operating activities. We retired approximately $414 million of long-term debt, excluding $25 million related to an asset sale, and decreased our short-term debt by $103 million. We also issued approximately $73 million of long-term debt.

Off-balance Sheet Arrangements

We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our current policy restricts the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business. Our off-balance sheet arrangements have not changed significantly from year-end. For complete information on each of these off-balance sheet arrangements see the “Minority Interest and Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2004 Annual Report.
 
SIGNIFICANT MATTERS

Texas Regulatory Activity

Texas Restructuring

The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items in TCC’s future true-up filing. TCC has asked permission from the PUCT to file its True-up Proceeding after the sales of its interest in STP have been concluded. If the request is approved, it is anticipated that TCC’s True-up Proceeding will be filed during the second quarter of 2005 seeking recovery of its net regulatory asset of $1.6 billion for its net stranded cost and other true-up items which it believes the Texas Restructuring Legislation allows.

TCC continues to accrue a carrying cost at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 further clarifying how the amounts are to be calculated. This resulted in a reduction in TCC’s accrued carrying costs based on the methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes (ADFIT) on TCC’s net stranded cost and other true-up items retroactive to January 1, 2004. In the first quarter of 2005, TCC accrued carrying costs of $21 million, which was more than offset by an adverse adjustment of $27 million based on this order. The net reduction of $6 million in carrying costs is included in Other Income in the first quarter of 2005 on the accompanying Consolidated Statements of Income.

As of March 31, 2005, TCC has computed carrying costs of $450 million of which $296 million was recognized as income in 2004 and the first quarter of 2005. The remaining equity component of the carrying cost, of $154 million, will be recognized in income as collected.

When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated transmission and distribution (T&D) rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

We believe that our recorded net true-up regulatory asset of $1.6 billion at March 31, 2005 is recoverable under the Texas Restructuring Legislation; however, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered. To the extent decisions of the PUCT in TCC’s future True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated companies, additional material disallowances and reductions of recorded carrying costs are possible, which could have a material adverse effect on future results of operations, cash flows and possibly financial condition.

TCC Rate Case

TCC has an on-going T&D rate review before the PUCT. In that rate review, the PUCT has issued various decisions and conducted additional hearings in March 2005. At an open meeting on April 13, 2005, the PUCT decided all remaining issues except the amount of affiliate expenses to include in revenue requirements which the PUCT decided to defer. Adjusted for the decisions approved by the PUCT through April 13, 2005, the ALJ’s recommended disallowances of affiliate expenses would produce an annual rate reduction of $25 million to $52 million. If TCC were to prevail on the affiliate expenses issue, the result would be an annual rate increase of $2 million. An order reducing TCC’s rates could have an adverse effect on future results of operations and cash flows.

Ohio Regulatory Activity

Ohio Restructuring

In January 26, 2005 the PUCO approved Rate Stabilization Plans for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for up to 4% of additional annual generation rate increases based on supporting the need for additional revenues. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. First quarter of 2005 pretax earnings were increased by $13 million for CSPCo and $32 million for OPCo as a result of implementing this provision of the Rate Stabilization Plans. Of these amounts approximately $8 million for CSPCo and $21 for OPCo relate to 2004 environmental carrying costs and RTO costs.

IGCC Power Plant

On March 18, 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposes cost recovery associated with the IGCC plant in three phases. In Phase 1, the Ohio companies would recover approximately $18 million in pre-construction costs during 2006. In Phase 2, the Ohio companies would recover approximately $237 million in construction financing costs from 2007 through mid-2010 when the plant is projected to be placed in commercial operation. The proposed recoveries in Phases 1 and 2 will be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008, under their Rate Stabilization Plans. In Phase 3, which begins when the plant enters commercial operation, projected to be in mid-2010, the Ohio companies would recover the projected $1.0 billion cost of the plant and a return on the unrecovered cost over its operating life along with fuel, replacement power and operation and maintenance costs.

Oklahoma Regulatory Activity

PSO Rate Review

PSO is involved in a commission staff-initiated rate review before the OCC seeking to increase its base rates, while various other parties made recommendations to reduce PSO’s base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. Pending approval by the OCC, the settlement provides for a $7 million base rate reduction partially offset by a $6 million reduction in annual depreciation expense. The settlement also provides for recovery of $9 million of deferred fuel and the continuation of the vegetation management rider. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC did not approve the settlement in time for implementation of new base rates in May 2005 as agreed to by the parties, which voids the settlement. The OCC issued an Order approving the stipulation on May 2, 2005 with one exception. The Order approves the implementation of new base rates in June 2005 versus the stipulation date of May 2005.

PSO Fuel and Purchased Power

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices.

In the proceeding, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and AEP West companies should have received more margins. The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. Using the intervenors’ method, PSO estimates that the increase in margins would be $29 million through March 31, 2005. In April 2005, the OCC heard arguments from intervenors that requested the OCC to conduct a prudence review of PSO’s fuel and purchased power for 2003. Management is unable to predict if the OCC will order a prudence review of PSO’s fuel and purchased power activities for 2003 or the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

FERC Order on Regional Through and Out Rates

A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. Billing statements from PJM for the first quarter of 2005 did not reflect any credits to AEP for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP accrued $26 million of SECA revenue in the first quarter of 2005 and has a receivable for SECA revenues of $37 million at March 31, 2005. SECA billings by PJM crediting AEP for their SECA revenue are scheduled to begin in May 2005 with retroactive adjustments to be billed by PJM in June and July 2005.

The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA transition rates was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be sufficient to replace the SECA transition rate revenues and whether the new rates will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, if AEP zonal rates are not sufficiently increased by the FERC after March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.

Litigation

We continue to be involved in various litigation described in the “Significant Factors - Litigation” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2004 Annual Report. The 2004 Annual Report should be read in conjunction with this report in order to understand other litigation that did not have significant changes in status since the issuance of our 2004 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition. Other matters described in the 2004 Annual Report that did not have significant changes during the first quarter of 2005, that should be read in order to gain a full understanding of our current litigation include: (1) Bank of Montreal Claim, (2) Coal Transportation Dispute, (3) Shareholders’ Litigation, (4) Merger Litigation and (5) Potential Uninsured Losses.

Federal EPA Complaint and Notice of Violation

See discussion of New Source Review Litigation within “Significant Factors - Environmental Matters.”

Enron Bankruptcy  

In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain of our subsidiaries had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - - Right to use of cushion gas agreements - In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in the state court of Texas seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to defend vigorously against BOA’s claims.

In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel reservoir and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA objected to the Magistrate Judge’s decision. On April 6, 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. We have objected to Enron’s attempted rejection of these agreements and have filed an adversary proceeding contesting Enron’s right to reject these agreements.

In January 2005, we sold a 98% limited partner interest in HPL. We have indemnified the buyer of the 98% interest in HPL against any damages resulting from the BOA litigation up to the purchase price. The recognition and the amount of the gain is dependent upon the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter.

Enron Bankruptcy - Commodity trading settlement disputes - 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 in connection with gas related trading transactions. We asserted our right to offset trading payables owed to various Enron entities against trading receivables due to several of our subsidiaries. The parties are currently in nonbinding court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding court-sponsored mediation.
 
Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy 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. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.
 
Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and will file a petition for review of this Initial Decision. The SEC will review the Initial Decision.
Natural Gas Markets Lawsuits

In November 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County, California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. 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. Since then, a number of cases have been filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. In some of these cases, AEP (or a subsidiary) is among the companies named as defendants. These cases are at various pre-trial stages. Several of these cases had been transferred to the United States District Court for the District of Nevada but were subsequently remanded to California state court. In April 2005, the judge in Nevada dismissed one of the remaining cases in which AEP was a defendant on the basis of the filed rate doctrine. We will continue to defend vigorously each case where an AEP company is a defendant.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against us and four of our subsidiaries, certain nonaffiliated 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. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, sought leave to intervene as plaintiffs asserting similar claims. We filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit. In April 2005, the defendants filed a Motion to Stay this case, pending the outcome of the appeal in the TCE case.

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. Thereafter, two similar actions were filed in the same court against a number of companies including AEP and AEPES making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. On December 5, 2003, the Court issued its initial Pretrial Order consolidating all related cases, appointing co-lead counsel and providing for the filing of an amended consolidated complaint. In January 2004, plaintiffs filed an amended consolidated complaint. We and the other defendants filed a motion to dismiss the complaint, which the Court denied in September 2004. Plaintiffs have filed a Motion for Class Certification. The defendants, including AEP and AEPES, filed their opposition to class certification on April 8, 2005. Briefing on the issue of class certification is expected to be completed in the second quarter of 2005. Discovery is continuing in the case with a discovery cut-off date of June 30, 2005. We intend to defend vigorously against these claims.

SWEPCo Notice of Enforcement and Notice of Citizen Suit 

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and Pirkey plants. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo will file a response to the complaint in May 2005.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of $228,312 against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the references to a specific heat input value for each Welsh unit.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of $5,550 against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, cash flows or financial condition.

TEM Litigation

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to us. We have subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 270 MW). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo has also agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.) (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) has provided a limited guaranty.

In November 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted AEP partial summary judgment on this issue, holding that the absence of operating protocols does not prevent enforcement of the PPA.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for these electric power products under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM, and Tractebel SA under the guaranty, damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005.

Environmental Matters

As discussed in our 2004 Annual Report, there are emerging environmental control requirements that we expect will result in substantial capital investments and operational costs. The sources of these future requirements include:

·
Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from coal-fired power plants,
·
Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and
·
Possible future requirements to reduce carbon dioxide emissions to address concerns about global climatic change.

This discussion updates certain events occurring in 2005. You should also read the “Significant Factors - Environmental Matters” section within Management’s Financial Discussion and Analysis of Results of Operations in our 2004 Annual Report for a description of all environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) the Comprehensive Environmental Response Compensation and Liability Act (Superfund) and state remediation, (4) global climate change, (5) carbon dioxide public nuisance claims, (6) costs for spent nuclear fuel disposal and decommissioning, and (7) Clean Water Act regulation.

Future Reduction Requirements for SO2 , NOx and Mercury

Regulatory Emissions Reductions

In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO2, NOx and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

·
The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO2 and NOx emissions across the Eastern United States (29 states and the District of Columbia) and make progress toward attainment of the new fine particulate matter and ground-level ozone national ambient air quality standards. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program.
·
The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.

On March 14, 2005, the Administrator of the Federal EPA signed the final CAIR. The rule is slightly revised from the proposed version released in January 2004, and includes both a seasonal and annual NOx control program as well as an annual SO2 control program. All of the states in which our generating facilities are located will be subject to the regional and annual NOx control programs and the annual SO2 control program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the annual programs only. Arkansas will be subject to the seasonal NOx control program only. Oklahoma is not affected by CAIR. In addition, the compliance deadline for Phase I for the NOx control program has been accelerated to 2009, and will replace any obligations imposed by the NOx State Implementation Plan (SIP) Call in 2009.

On March 15, 2005, the Administrator of the Federal EPA signed a final Clean Air Mercury Rule (CAMR) that will permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. The final CAMR imposes a national cap on mercury emissions from coal-fired power plants of 38 tons by 2010 and 15 tons by 2018.

The changes in the Federal EPA’s final CAIR and CAMR have not caused us to revise our estimates of the capital investments necessary to achieve compliance with these requirements. However, final rules give states substantial discretion in developing their rules to implement these cap-and-trade programs, and states will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here. If states elect not to participate in the federal cap-and-trade programs, or elect to impose additional requirements on individual units that are already subject to CAIR and/or the CAMR, our costs could increase significantly. The cost of compliance could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.

New Source Review Litigation

Under the CAA, 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 Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The Court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period.

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. The Federal EPA and the states each have filed an additional complaint alleging violations of the new source review requirements at units at the Amos and Conesville plants that were not allowed to be added to the pending case. These separate complaints have been assigned to the same judge in the Southern District Court.

In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA in the U.S. District Court for the Southern District of Ohio alleging that violations of the prevention of significant deterioration and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio SIP occurred at the J.M. Stuart Station, and seeking injunctive relief and civil penalties. Stuart Station is jointly owned by CSPCo (26%) and two nonaffiliated utilities. The owners have filed a motion to dismiss portions of the complaint, based primarily upon the federal statute of limitations. In March 2005, in an unrelated case alleging new source review permitting claims against the Tennessee Valley Authority (TVA), the court granted a motion to dismiss the claims against TVA on similar grounds. The owners have advised the court of this new decision. We believe the allegations in the complaint are without merit, and intend to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

We are unable to estimate the loss or range of loss related to any contingent liability we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If 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.

Emergency Release Reporting

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances that cross property boundaries of the releasing facility.

On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. The Federal EPA's Complaint seeks an immaterial amount of civil penalties. I&M has requested a hearing and raised several defenses to the claim, including federally permitted release exemption from reporting. Negotiations on the penalty amount are continuing.

On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant SCR system. The Federal EPA indicated its intent to seek civil penalties. In February 2005, OPCo provided relevant information that the Federal EPA should consider in advance of any filing.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

As a major power producer and marketer of wholesale electricity, coal and emission allowances, 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.

In the Investment-Gas Operations segment, AEP continues to hold forward gas contracts that were not sold with the gas pipeline and storage assets. These contracts are primarily financial derivatives with some physical contracts which will gradually wind down and completely expire in 2011. The AEP risk objective is to keep these positions risk neutral through maturity.

We have established policies and procedures that allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies have been reviewed with our Board of Directors and approved by our Risk Executive Committee. Our Chief Risk Officer administers our risk policies and procedures. The Risk Executive Committee establishes risk limits, approves risk policies, and assigns responsibilities regarding the oversight and management of risk and monitors risk levels. Members of this committee receive daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, Credit Risk Management, Market Risk Oversight, and senior financial and operating managers.

We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts. The CCRO is composed of the chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and have embraced the disclosure standards. The following tables provide information on our risk management activities:
 
Mark-to-Market Risk Management Contract Net Assets (Liabilities)

This table provides detail on changes in our mark-to-market (MTM) net asset or liability balance sheet position from one period to the next.
 
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in millions)

   
Utility Operations
 
Investments-Gas Operations
 
Investments-UK Operations
 
Total
 
Total MTM Risk Management Contract Net Asset
  (Liabilities) at December 31, 2004
 
$
277
 
$
-
 
$
(12
)
$
265
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(37
)
 
(5
)
 
12
   
(30
)
Fair Value of New Contracts When Entered During the Period (b)
   
1
   
-
   
-
   
1
 
Net Option Premiums Paid/(Received) (c)
   
-
   
-
   
-
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
   
-
   
-
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
29
   
(5
)
 
-
   
24
 
Changes in Fair Value of Risk Management Contracts Allocated to
  Regulated Jurisdictions (e)
   
(8
)
 
-
   
-
   
(8
)
Total MTM Risk Management Contract Net Assets
  (Liabilities) at March 31, 2005
 
$
262
 
$
(10
)
$
-
   
252
 
Net Cash Flow and Fair Value Hedge   Contracts (f)
                     
(61
)
Ending Net Risk Management Assets at March 31, 2005
                   
$
191
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized gains from risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(c)
“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts entered in 2005.
(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)
“Changes 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 assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)
“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed in detail within the following pages.

 
Detail on MTM Risk Management Contract Net Assets (Liabilities)
As of March 31, 2005
(in millions)

   
Utility Operations
 
Investments-Gas Operations
 
Total
 
Current Assets
 
$
545
 
$
291
 
$
836
 
Noncurrent Assets
   
497
   
146
   
643
 
Total Assets
   
1,042
   
437
   
1,479
 
                     
Current Liabilities
   
(480
)
 
(286
)
 
(766
)
Noncurrent Liabilities
   
(300
)
 
(161
)
 
(461
)
Total Liabilities
   
(780
)
 
(447
)
 
(1,227
)
                     
Total Net Assets (Liabilities), excluding Hedges
 
$
262
 
$
(10
)
$
252
 

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in millions)

   
MTM Risk Management Contracts (a)
 
PLUS:
Hedges
 
Total (b)
 
Current Assets
 
$
836
 
$
29
 
$
865
 
Noncurrent Assets
   
643
   
3
   
646
 
Total MTM Derivative Contract Assets
   
1,479
   
32
   
1,511
 
                     
Current Liabilities
   
(766
)
 
(84
)
 
(850
)
Noncurrent Liabilities
   
(461
)
 
(9
)
 
(470
)
Total MTM Derivative Contract Liabilities
   
(1,227
)
 
(93
)
 
(1,320
)
                     
Total MTM Derivative Contract Net Assets
 
$
252
 
$
(61
)
$
191
 

(a)
Does not include Cash Flow and Fair Value Hedges.
(b)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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 (liabilities) provides two fundamental pieces of information.

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 (Liabilities)
Fair Value of Contracts as of March 31, 2005
(in millions)

   
Remainder 2005
 
2006
 
2007
 
2008
 
2009
 
After 2009
 
Total (c)
 
Utility Operations:
                                    
Prices Actively Quoted - Exchange Traded Contracts
 
$
(67
)
$
18
 
$
22
 
$
-
 
$
-
 
$
-
 
$
(27
)
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
131
   
63
   
46
   
21
   
-
   
-
   
261
 
Prices Based on Models and Other Valuation Methods (b)
   
(2
)
 
(36
)
 
(13
)
 
20
   
31
   
28
   
28
 
Total
 
$
62
 
$
45
 
$
55
 
$
41
 
$
31
 
$
28
 
$
262
 
                                             
Investments - Gas Operations:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
34
 
$
(7
)
$
4
 
$
-
 
$
-
 
$
-
 
$
31
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
(21
)
 
(3
)
 
-
   
-
   
-
   
-
   
(24
)
Prices Based on Models and Other Valuation Methods (b)
   
(3
)
 
(3
)
 
(3
)
 
(2
)
 
(4
)
 
(2
)
 
(17
)
Total
 
$
10
 
$
(13
)
$
1
 
$
(2
)
$
(4
)
$
(2
)
$
(10
)
                                             
Total:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
(33
)
$
11
 
$
26
 
$
-
 
$
-
 
$
-
 
$
4
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
110
   
60
   
46
   
21
   
-
   
-
   
237
 
Prices Based on Models and Other Valuation Methods (b)
   
(5
)
 
(39
)
 
(16
)
 
18
   
27
   
26
   
11
 
Total
 
$
72
 
$
32
 
$
56
 
$
39
 
$
27
 
$
26
 
$
252
 

(a)
Prices provided by other external sources - Reflects information obtained from over-the-counter brokers (OTC), 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 is limited, such valuations are classified as modeled.
(c)
Amounts exclude Cash Flow and Fair Value Hedges.

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 (contract maturities) of the liquid portion of each energy market.
 

Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of March 31, 2005

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in months)
Natural Gas
 
Futures
 
NYMEX/Henry Hub
 
60
   
Physical Forwards
 
Gulf Coast, Texas
 
24
   
Swaps
 
Gas East - Northeast, Mid-continent, Gulf Coast, Texas
  24 
   
Swaps
 
Gas West - Rocky Mountains, West Coast
 
24
   
Exchange Option Volatility
 
NYMEX/Henry Hub
 
12
             
Power
 
Futures
 
Power East - PJM
 
36
   
Physical Forwards
 
Power East - Cinergy
 
21
   
Physical Forwards
 
Power East - PJM West
 
33
   
Physical Forwards
 
Power East - AEP Dayton (PJM)
 
21
   
Physical Forwards
 
Power East - NEPOOL
 
21
   
Physical Forwards
 
Power East - NYPP
 
33
   
Physical Forwards
 
Power East - ERCOT
 
48
   
Physical Forwards
 
Power East - Com Ed
 
21
   
Physical Forwards
 
Power West - Palo Verde, North Path 15, South Path 15,
  MidColumbia, Mead
 
45
   
Peak Power Volatility (Options)
 
Cinergy
 
12
   
Peak Power Volatility (Options)
 
PJM
 
12
             
Crude Oil
 
Swaps
 
West Texas Intermediate
 
36
             
Emissions
 
Credits
 
SO2, NOx
 
45
             
Coal
 
Physical Forwards
 
PRB, NYMEX, CSX
 
21

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power and gas operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate risk to existing floating rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The tables below provide detail on effective cash flow hedges under SFAS 133 included in our Balance Sheets. The data in the first table indicates the magnitude of SFAS 133 hedges that we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. This table further indicates what portions of these hedges are expected to be reclassified into net income in the next 12 months. The second table provides the nature of changes from December 31, 2004 to March 31, 2005.

Information on energy commodity risk management activities is presented separately from interest rate risk management 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 March 31, 2005
(in millions)

   
Accumulated Other Comprehensive Income(Loss)
After Tax (a)
 
Portion Expected to be Reclassified to Earnings During the Next 12 Months (b)
 
Power and Gas
 
$
(36
)
$
(34
)
Interest Rate
   
(15
)
 
(3
               
Total
 
$
(51
)
$
(37
 
 
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in millions)

   
Power and Gas
 
Interest
Rate
 
Total
 
Beginning Balance, December 31, 2004
 
$
23
 
$
(23
)
$
-
 
Changes in Fair Value (c)
   
(34
)
 
8
   
(26
)
Reclassifications from AOCI to Net Income (d)
   
(25
)
 
-
   
(25
)
Ending Balance, March 31, 2005
 
$
(36
)
$
(15
)
$
(51
)

(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 cash flow hedges during the reporting period that are not yet settled at March 31, 2005. 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.

Credit Risk

We limit 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 our internal credit rating criteria will we extend unsecured credit. We use Moody’s, S&P and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. Our analysis, in conjunction with the rating agencies’ information, is used to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. At March 31, 2005, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 17.6%, expressed in terms of net MTM assets and net receivables. As of March 31, 2005, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality
 
 Exposure Before Credit Collateral
 
Credit Collateral
 
Net Exposure
 
Number of Counterparties
 >10%
 
Net Exposure of Counterparties >10%
 
Investment Grade
 
$
781
 
$
191
 
$
590
   
1
 
$
97
 
Split Rating
   
18
   
7
   
11
   
2
   
11
 
Noninvestment Grade
   
269
   
143
   
126
   
3
   
93
 
No External Ratings:
                               
 
Internal Investment Grade
   
44
   
-
   
44
   
2
   
32
 
 
Internal Noninvestment Grade
   
14
   
3
   
11
   
2
   
11
 
Total
 
$
1,126
 
$
344
 
$
782
   
10
 
$
244
 

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2007. Please note that this table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of March 31, 2005

   
Remainder 2005
 
2006
 
2007
 
Estimated Plant Output Hedged
   
89
%
 
87
%
 
88
%

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at March 31, 2005, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR year-to-date:

VaR Model
 
Three Months Ended March 31, 2005
 
Twelve Months Ended December 31, 2004
 
(in millions)
 
(in millions)
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
$2
 
$5
 
$2
 
$1
 
$3
 
$19
 
$5
 
$1

Our VaR model results are adjusted using standard statistical treatments to calculate the CCRO VaR reporting metrics listed below.

CCRO VaR Metrics
(in millions)

   
March 31, 2005
 
Average for
Year-to-Date 2005
 
High for
Year-to-Date 2005
 
Low for Year-to-Date 2005
 
95% Confidence Level, Ten-Day Holding Period
 
$
8
 
$
9
 
$
17
 
$
5
 
                           
99% Confidence Level, One-Day Holding Period
 
$
3
 
$
4
 
$
7
 
$
2
 

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $653 million at March 31, 2005 and $601 million at December 31, 2004. We would not expect to liquidate our 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, cash flows or consolidated financial position.

We employ risk management contracts including 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. We engage in risk management of electricity, gas and to a lesser degree other commodities, principally coal and emissions. As a result, we are subject to price risk. The amount of risk taken is controlled by risk management operations and our Chief Risk Officer and his staff. When risk management activities exceed 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 INCOME
For the Three Months Ended March 31, 2005 and 2004
(in millions, except per-share amounts)
(Unaudited)

   
2005
 
2004
 
REVENUES
         
Utility Operations
 
$
2,537
 
$
2,581
 
Gas Operations
   
357
   
652
 
Other
   
89
   
131
 
TOTAL
   
2,983
   
3,364
 
               
EXPENSES
             
Fuel for Electric Generation
   
771
   
694
 
Purchased Electricity for Resale
   
130
   
83
 
Purchased Gas for Resale
   
249
   
585
 
Maintenance and Other Operation
   
790
   
864
 
Depreciation and Amortization
   
327
   
319
 
Taxes Other Than Income Taxes
   
188
   
193
 
TOTAL
   
2,455
   
2,738
 
               
OPERATING INCOME
   
528
   
626
 
               
Other Income
   
239
   
62
 
Other Expense
   
(66
)
 
(36
)
               
INTEREST AND OTHER CHARGES
             
Interest Expense
   
173
   
199
 
Preferred Stock Dividend Requirements of Subsidiaries
   
2
   
2
 
TOTAL
   
175
   
201
 
               
INCOME BEFORE INCOME TAXES
   
526
   
451
 
Income Taxes
   
172
   
162
 
               
INCOME BEFORE DISCONTINUED OPERATIONS
   
354
   
289
 
               
DISCONTINUED OPERATIONS, Net of Tax
   
1
   
(7
)
               
NET INCOME
 
$
355
 
$
282
 
               
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING
   
393
   
395
 
               
EARNINGS PER SHARE
             
Income Before Discontinued Operations
 
$
0.90
 
$
0.73
 
Discontinued Operations
   
-
   
(0.02
)
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE)
 
$
0.90
 
$
0.71
 
               
CASH DIVIDENDS PAID PER SHARE
 
$
0.35
 
$
0.35
 

See Notes to Consolidated Financial Statements



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(in millions)
(Unaudited)

   
2005
 
2004
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,261
 
$
320
 
Other Temporary Cash Investments
   
181
   
275
 
Accounts Receivable:
             
Customers
   
847
   
930
 
Accrued Unbilled Revenues
   
256
   
592
 
Miscellaneous
   
65
   
79
 
Allowance for Uncollectible Accounts
   
(43
)
 
(77
)
  Total Receivables
   
1,125
   
1,524
 
Fuel, Materials and Supplies
   
636
   
852
 
Risk Management Assets
   
865
   
737
 
Margin Deposits
   
178
   
113
 
Other
   
157
   
200
 
TOTAL
   
4,403
   
4,021
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
16,019
   
15,969
 
Transmission
   
6,310
   
6,293
 
Distribution
   
10,378
   
10,280
 
Other (including gas, coal mining and nuclear fuel)
   
3,152
   
3,585
 
Construction Work in Progress
   
1,329
   
1,159
 
Total
   
37,188
   
37,286
 
Accumulated Depreciation and Amortization
   
14,589
   
14,485
 
TOTAL - NET
   
22,599
   
22,801
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
3,653
   
3,601
 
Securitized Transition Assets
   
632
   
642
 
Spent Nuclear Fuel and Decommissioning Trusts
   
1,080
   
1,053
 
Investments in Power and Distribution Projects
   
136
   
154
 
Goodwill
   
76
   
76
 
Long-term Risk Management Assets
   
646
   
470
 
Prepaid Pension Obligations
   
385
   
386
 
Other
   
851
   
831
 
TOTAL
   
7,459
   
7,213
 
               
Assets Held for Sale
   
636
   
628
 
               
TOTAL ASSETS
 
$
35,097
 
$
34,663
 

See Notes to Consolidated Financial Statements.


 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2005 and December 31, 2004
(Unaudited)

     
2005
 
2004
 
CURRENT LIABILITIES
   
(in millions)
 
Accounts Payable
   
$
876
 
$
1,051
 
Short-term Debt
     
19
   
23
 
Long-term Debt Due Within One Year (a)
     
1,685
   
1,279
 
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption
     
-
   
66
 
Risk Management Liabilities
     
850
   
608
 
Accrued Taxes
     
865
   
611
 
Accrued Interest
     
171
   
180
 
Customer Deposits
     
469
   
414
 
Other
     
597
   
775
 
TOTAL
     
5,532
   
5,007
 
                 
NONCURRENT LIABILITIES
               
Long-term Debt (a)
     
10,674
   
11,008
 
Long-term Risk Management Liabilities
     
470
   
329
 
Deferred Income Taxes
     
4,774
   
4,819
 
Regulatory Liabilities and Deferred Investment Tax Credits
     
2,616
   
2,540
 
Asset Retirement Obligations
     
841
   
827
 
Employee Benefits and Pension Obligations
     
632
   
730
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
     
164
   
166
 
Deferred Credits and Other
     
810
   
411
 
TOTAL
     
20,981
   
20,830
 
                 
Liabilities Held for Sale
     
255
   
250
 
                 
TOTAL LIABILITIES
     
26,768
   
26,087
 
                 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
     
61
   
61
 
                 
Commitments and Contingencies (Note 5)
               
                 
COMMON SHAREHOLDERS’ EQUITY
               
Common Stock Par Value $6.50:
               
                 
2005
 
2004
                           
Shares Authorized
600,000,000
 
600,000,000
                           
Shares Issued
405,433,490
 
404,858,145
                           
(21,499,992 and 8,999,992 shares were held in treasury at March 31, 2005 and December 31, 2004,
  respectively)
     
2,635
   
2,632
 
Paid-in Capital
     
3,786
   
4,203
 
Retained Earnings
     
2,241
   
2,024
 
Accumulated Other Comprehensive Income (Loss)
     
(394
)
 
(344
)
TOTAL
     
8,268
   
8,515
 
                 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
   
$
35,097
 
$
34,663
 

(a) See Accompanying Schedule.

See Notes to Consolidated Financial Statements.

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(in millions)
(Unaudited)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
355
 
$
282
 
Plus: (Income) Loss from Discontinued Operations
   
(1
)
 
7
 
Income from Continuing Operations
   
354
   
289
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
327
   
319
 
Accretion of Asset Retirement Obligations
   
18
   
15
 
Deferred Income Taxes
   
(19
)
 
49
 
Deferred Investment Tax Credits
   
(8
)
 
(9
)
Carrying Costs
   
(20
)
 
-
 
Amortization of Deferred Property Taxes
   
(82
)
 
(93
)
Mark-to-Market of Risk Management Contracts
   
27
   
(59
)
Pension Contributions
   
(102
)
 
-
 
Over/Under Fuel Recovery
   
52
   
30
 
Gain on Sales of Assets
   
(115
)
 
(1
)
Change in Other Noncurrent Assets
   
(66
)
 
2
 
Change in Other Noncurrent Liabilities
   
(64
)
 
10
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
104
   
183
 
Fuel, Materials and Supplies
   
64
   
65
 
Accounts Payable
   
39
   
(95
)
Taxes Accrued
   
245
   
189
 
Customer Deposits
   
55
   
43
 
Interest Accrued
   
(9
)
 
(10
)
Other Current Assets
   
(8
)
 
5
 
Other Current Liabilities
   
(119
)
 
(35
)
Net Cash Flows From Operating Activities
   
673
   
897
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(465
)
 
(305
)
Change in Other Temporary Cash Investments, Net
   
94
   
64
 
Investment in Discontinued Operations, Net
   
-
   
7
 
Proceeds from Sale of Assets
   
1,157
   
40
 
Other
   
2
   
8
 
Net Cash Flows From (Used For) Investing Activities
   
788
   
(186
)
               
FINANCING ACTIVITIES
             
Issuance of Common Stock
   
17
   
10
 
Repurchase of Common Stock
   
(434
)
 
-
 
Issuance of Long-term Debt
   
580
   
73
 
Change in Short-term Debt, Net
   
31
   
(103
)
Retirement of Long-term Debt
   
(510
)
 
(414
)
Retirement of Preferred Stock
   
(66
)
 
(4
)
Dividends Paid on Common Stock
   
(138
)
 
(138
)
Net Cash Flows Used For Financing Activities
   
(520
)
 
(576
)
               
Net Increase in Cash and Cash Equivalents
   
941
   
135
 
Cash and Cash Equivalents at Beginning of Period
   
320
   
778
 
Cash and Cash Equivalents at End of Period
 
$
1,261
 
$
913
 
               
Net Increase in Cash and Cash Equivalents from Discontinued Operations
 
$
-
 
$
24
 
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period
   
-
   
13
 
Cash and Cash Equivalents from Discontinued Operations - End of Period
 
$
-
 
$
37
 

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest, net of capitalized amounts, was $170 million and $198 million in 2005 and 2004, respectively. Cash received for income taxes was $57
  million in both 2005 and 2004. Noncash acquisitions under capital leases were $9 million and $4 million in 2005 and 2004, respectively.
 
See Notes to Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(in millions)
(Unaudited)

   
Common Stock
         
Accumulated Other Comprehensive Income (Loss)
     
   
Shares
 
Amount
 
Paid-in Capital
 
Retained Earnings
   
Total
 
DECEMBER 31, 2003
   
404
 
$
2,626
 
$
4,184
 
$
1,490
 
$
(426
)
$
7,874
 
Issuance of Common Stock
   
1
   
4
   
6
               
10
 
Common Stock Dividends
                     
(138
)
       
(138
)
TOTAL
                                 
7,746
 
                                       
COMPREHENSIVE INCOME
                                     
Other Comprehensive Income, Net of Tax:
                                     
 
Foreign Currency Translation Adjustments,
  Net of Tax of $0
                           
8
   
8
 
 
Cash Flow Hedges, Net of Tax of $12
                           
22
   
22
 
 
Minimum Pension Liability, Net of Tax of $10
                           
17
   
17
 
NET INCOME
                     
282
         
282
 
TOTAL COMPREHENSIVE INCOME
                                 
329
 
MARCH 31, 2004
   
405
 
$
2,630
 
$
4,190
 
$
1,634
 
$
(379
)
$
8,075
 
                                       
DECEMBER 31, 2004
   
405
 
$
2,632
 
$
4,203
 
$
2,024
 
$
(344
)
$
8,515
 
Issuance of Common Stock
         
3
   
14
               
17
 
Common Stock Dividends
                     
(138
)
       
(138
)
Repurchase of Common Stock
               
(434
)
             
(434
)
Other
               
3
               
3
 
TOTAL
                                 
7,963
 
                                       
COMPREHENSIVE INCOME
                                     
Other Comprehensive Income (Loss), Net of Tax:
                                     
 
Foreign Currency Translation Adjustments,
  Net of Tax of $0
                           
1
   
1
 
 
Cash Flow Hedges, Net of Tax of $28
                           
(51
)
 
(51
)
NET INCOME
                     
355
         
355
 
TOTAL COMPREHENSIVE INCOME
                                 
305
 
MARCH 31, 2005
   
405
 
$
2,635
 
$
3,786
 
$
2,241
 
$
(394
)
$
8,268
 

See Notes to Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
   
(in millions)
 
             
First Mortgage Bonds
 
$
417
 
$
417
 
Defeased TCC First Mortgage Bonds (a)
   
84
   
84
 
Installment Purchase Contracts
   
1,935
   
1,773
 
Notes Payable
   
935
   
939
 
Senior Unsecured Notes
   
7,667
   
7,717
 
Securitization Bonds
   
669
   
698
 
Notes Payable to Trust
   
113
   
113
 
Equity Unit Senior Notes
   
345
   
345
 
Long-term DOE Obligation (b)
   
230
   
229
 
Other Long-term Debt
   
8
   
14
 
Equity Unit Contract Adjustment Payments
   
7
   
9
 
Unamortized Discount (net)
   
(51
)
 
(51
)
TOTAL LONG-TERM DEBT OUTSTANDING
   
12,359
   
12,287
 
Less Portion Due Within One Year
   
1,685
   
1,279
 
               
TOTAL LONG-TERM PORTION
 
$
10,674
 
$
11,008
 

(a)
On May 7, 2004, we deposited cash and treasury securities of $125 million with a trustee to defease all of TCC’s outstanding First Mortgage Bonds. Trust fund assets related to this obligation of $70 and $72 million are included in Other Temporary Cash Investments at March 31, 2005 and December 31, 2004, respectively, and $22 million are included in Other Noncurrent Assets in the Consolidated Balance Sheets at both March 31, 2005 and December 31, 2004. Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.
(b)
Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. I&M is the only AEP subsidiary that generated electric power with nuclear fuel prior to that date. Trust fund assets of $261 million and $262 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts in the Consolidated Balance Sheets at March 31, 2005 and December 31, 2004, respectively.
 
 

 
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

 
 1.
 Significant Accounting Matters
 2.
 New Accounting Pronouncements
 3.
 Rate Matters
 4.
 Customer Choice and Industry Restructuring
 5.
 Commitments and Contingencies
 6.
 Guarantees
 7.
 Dispositions, Discontinued Operations and Assets Held for Sale
 8.
 Benefit Plans
 9.
 Business Segments
10.
 Financing Activities
 
 
 
 
 
 
 
 



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited interim financial statements should be read in conjunction with the 2004 Annual Report as incorporated in and filed with our 2004 Form 10-K.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments that are necessary for a fair presentation of our results of operations for interim periods.

Other Income and Other Expense 

The following table provides the components of Other Income and Other Expense as presented in our Consolidated Statements of Income:

   
Three Months Ended
March 31,
 
   
2005
 
2004
 
   
(in millions)
 
Other Income:
             
Interest and Dividend Income
 
$
11
 
$
6
 
Equity Earnings
   
5
   
7
 
Nonutility Revenue
   
63
   
29
 
Gain on Sale of Texas REPs
   
112
   
-
 
Carrying Charges
   
20
   
2
 
Other
   
28
   
18
 
Total Other Income
 
$
239
 
$
62
 
               
Other Expense:
             
Nonutility Expense
 
$
57
 
$
26
 
Other
   
9
   
10
 
Total Other Expense
 
$
66
 
$
36
 

Components of Accumulated Other Comprehensive Income (Loss) 

The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss):

   
March 31,
 
December 31,
 
   
2005
 
2004
 
Components
 
(in millions)
Foreign Currency Translation Adjustments, net of tax
 
$
7
 
$
6
 
Securities Available for Sale, net of tax
   
(1
)
 
(1
)
Cash Flow Hedges, net of tax
   
(51
)
 
-
 
Minimum Pension Liability, net of tax
   
(349
)
 
(349
)
Total
 
$
(394
)
$
(344
)

At March 31, 2005, we expect to reclassify approximately $37 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve months at the time the hedged transactions affect Net Income. The actual amounts that are reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ as a result of market fluctuations. At March 31, 2005, 21 months is the maximum length of time that we are hedging, with SFAS 133 designated contracts, our exposure to variability in future cash flows for forecasted transactions.
 
Accounting for Asset Retirement Obligations

The following is a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations:

   
Nuclear Decommissioning
 
Ash
Ponds
 
Wind Mills
and Mining Operations
 
Total
 
   
(in millions)
 
Asset Retirement Obligation Liability at January 1, 2005 Including Held for Sale
 
$
960
 
$
84
 
$
32
 
$
1,076
 
Accretion Expense
   
16
   
2
   
-
   
18
 
Asset Retirement Obligation Liability at   March 31, 2005 Including Held for Sale
   
976
   
86
   
32
   
1,094
 
                           
Less Asset Retirement Obligation Liability Held for Sale:
                         
South Texas Project (a)
   
(253
)
 
-
   
-
   
(253
)
                           
Asset Retirement Obligation Liability at March 31, 2005
 
$
723
 
$
86
 
$
32
 
$
841
 

(a)
We have signed an agreement to sell TCC’s share of South Texas Project (see “Texas Plants-South Texas Project” section of Note 7).

Accretion expense is included in Maintenance and Other Operation expense in our accompanying Consolidated Statements of Income.

At March 31, 2005 and December 31, 2004, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $962 million and $934 million, respectively, of which $819 million and $791 million relating to the Cook Plant was recorded in Spent Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities for South Texas Project totaling $143 million at March 31, 2005 and December 31, 2004, was classified as Assets Held for Sale in our Consolidated Balance Sheets.

Reclassifications 

Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income.

In connection with preparation of these financial statements, we concluded that it was appropriate to classify our auction rate securities as other temporary cash investments. Previously, such investments had been classified as cash and cash equivalents. Accordingly, we have revised the classification to exclude from cash and cash equivalents $103 million at December 31, 2004, and to include such amounts as other temporary cash investments. There were no auction rate securities held at March 31, 2005. At December 31, 2003, auction rate securities approximated $200 million. In addition, the following represents supplemental disclosures to the Statements of Cash Flows for the three-month periods ended March 31, 2005 and 2004:

   
2005
 
2004
 
   
(in millions)
 
Purchases of Auction Rate Securities
 
$
785
 
$
23
 
Proceeds from Sale of Auction Rate Securities
   
888
   
23
 

These revisions had no impact on previously reported results of operations, operating cash flows or working capital of the Company.
 
Prior Period Adjustment

As disclosed in our 2004 Annual Report, in the second quarter of 2004 we implemented FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003 (FSP FAS 106-2), retroactive to January 1, 2004. The effect of implementing FSP FAS 106-2 on the first quarter of 2004 is as follows:

Three Months Ended March 31, 2004
 
 Net Income
(in Millions)
 
 Earnings Per Share
 
               
Originally Reported
 
$
278
 
$
0.70
 
Effect of Medicare Subsidy
   
4
   
0.01
 
Restated
 
$
282
 
$
0.71
 
 
 
2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented during 2005 that we have determined relate to our operations.

SFAS 123 (revised 2004) “Share-Based Payment” (SFAS 123R)

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting previously available under Accounting Principles Board (APB) Opinion No. 25. The statement is effective as of the first annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially adopting the statement.

We will implement SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost will be based on the grant-date fair value of the equity award. We do not expect implementation of SFAS 123R to materially affect our results of operations, cash flows or financial condition.

In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. We will apply the principles of SAB 107 in conjunction with our adoption of SFAS 123R.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47)

In March 2005, the FASB issued FIN 47, which interprets the application of SFAS 143 “Accounting for Asset Retirement Obligations.” FIN 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Entities are required to record a liability for the fair value of a conditional asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

We will implement FIN 47 during the fourth quarter for the fiscal year ending December 31, 2005. Implementation will require an adjustment for the cumulative effect for the nonregulated operations of initially adopting FIN 47 to be recorded as a change in accounting principle, disclosure of pro forma liabilities and asset retirement obligations, and other additional disclosures. We have not completed our evaluation of any potential impact to our results of operations or financial condition.

EITF Issue 03-13 “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”

This issue developed a model for evaluating which cash flows are to be considered in determining whether cash flows have been or will be eliminated and what types of continuing involvement constitute significant continuing involvement when determining whether to report Discontinued Operations. During the first quarter of 2005, we applied this issue to components that are disposed of or classified as held for sale, including the HPL disposition. (see “Houston Pipe Line Company” section of Note 7).

Future Accounting Changes

The FASB’s standard-setting process is ongoing and 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. The FASB is currently working on several projects including business combinations, operating segments, liabilities and equity, revenue recognition, pension plans, fair value measurements, accounting changes and related tax impacts. We also expect to see more FASB projects as a result of their desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position.
 
 
3. RATE MATTERS 

As discussed in our 2004 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and at state commissions. The Rate Matters note within our 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending. The following sections discuss current activities and update the 2004 Annual Report.

PSO Fuel and Purchased Power

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices.

In the proceeding, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and AEP West companies should have received more margins. The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. Using the intervenors’ method, PSO estimates that the increase in margins would be $29 million through March 31, 2005. In April 2005, the OCC heard arguments from intervenors that requested the OCC to conduct a prudence review of PSO’s fuel and purchased power for 2003. Management is unable to predict if the OCC will order a prudence review of PSO’s fuel and purchased power activities for 2003 or the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

Michigan Fuel Recovery Plan

In September 2004, I&M filed its 2005 Power Supply Cost Recovery (PSCR) Plan, with the requested PSCR factors implemented pursuant to the statute effective with January 2005 billings, replacing the 2004 factors. On March 29, 2005, the Michigan Public Service Commission (MPSC) issued an order approving a settlement agreement authorizing the proposed 2005 PSCR Plan factors.
 
On March 31, 2005, I&M filed its 2004 PSCR Reconciliation seeking recovery of approximately $2 million of unrecovered PSCR fuel costs and interest proposed to be recovered through the application of customer bill surcharges during October 2005 through December 2005.

On April 28, 2005, the MPSC issued an Opinion and Order approving I&M’s proposed 2004 PSCR factors as billed and finding in favor of I&M on all issues, including the proposed treatment of net SO2 and NOx credits.

Indiana Settlement Agreement

In 2004, the IURC ordered the continuation of the fixed fuel adjustment charge on an interim basis through March 2005, pending the outcome of negotiations. Certain of the parties to the negotiations reached a settlement and signed an agreement on March 10, 2005, and filed the agreement with the IURC on March 14, 2005. The IURC may rule on the agreement during the second quarter of 2005.

The filed settlement freezes fuel rates for the March 2004 through June 2007 billing months at an increasing rate that includes 8.609 mills per KWH reflected in base rates. The settlement provides that the total fuel rates will be 9.88 mills per KWH from January 2005 through December 2005, 10.26 mills per KWH from January 2006 through December 2006, and 10.63 mills per KWH from January 2007 through June 2007. Pursuant to a separate IURC order, I&M began billing the 9.88 mills per KWH total fuel rate on an interim basis effective with the April 2005 billing month.

The settlement agreement also covers certain events at the Cook Plant. The settlement provides that if an outage greater than 60 days occurs at Cook Plant, the recovery of actual monthly fuel costs will be in effect for the outage period beyond 60 days, capped by the average AEP System Pool Primary Energy Rate (Primary Energy Rate), excluding I&M, as defined by the AEP System Interconnection Agreement and adjusted for losses. If a second outage greater than 60 days occurs, actual monthly fuel costs capped at the Primary Energy Rate would be recovered through June 2007. Over the term of the settlement, if total actual fuel costs (except during a Cook Plant outage greater than 60 days) are under the cap prices, the excess will be credited to customers over the next two fuel adjustment clause filings. Under the settlement fuel costs in excess of the cap price cannot be recovered. If Cook Plant operates at a capacity factor greater than 87% during the fuel rate freeze period, I&M will receive credit for 30% of the savings produced and customers will be credited with 70% of these savings over the first two fuel filings after the fuel rate freeze period ends in June 2007.

Pending approval of the IURC, this settlement agreement also freezes base rates from January 1, 2005 to June 30, 2007 at the rates in effect as of January 1, 2005. During this freeze period, I&M may not implement a general increase in base rates or implement a rider or cost deferral not established in the settlement agreement unless the IURC determines that a significant change in conditions beyond I&M’s control occurs or a material impact on I&M occurs as a result of federal, state or local regulation or statute that mandates reliability standards related to transmission or distribution costs.

If the settlement is approved by the IURC, fuel costs previously expensed since January 2005 exceeding the previously authorized level of 9.2 mills up to 9.88 mills (approximately $4 million through March 31, 2005) would be deferred for future recovery. If future fuel cost per KWH exceeds the caps, or if the base rate freeze precludes I&M from seeking timely rate increases to recover increases in I&M’s cost of service, future results of operations and cash flows would be adversely affected.

TCC Rate Case

TCC has an on-going transmission and distribution (T&D) rate review before the PUCT. In that rate review, the PUCT has issued various decisions and conducted additional hearings in March 2005. At an open meeting on April 13, 2005, the PUCT decided all remaining issues except the amount of affiliate expenses to include in revenue requirements which the PUCT decided to defer. Adjusted for the decisions approved by the PUCT through April 13, 2005, the ALJ’s recommended disallowances of affiliate expenses would produce an annual rate reduction of $25 million to $52 million. If TCC were to prevail on the affiliate expenses issue, the result would be an annual rate increase of $2 million. An order reducing TCC’s rates could have an adverse effect on future results of operations and cash flows.
 
TCC Unbundled Cost of Service (UCOS) Appeal

The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began. TCC placed new T&D rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. Certain PUCT rulings, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the 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 nonbypassable T&D rates charged to REPs, discriminates against residential and small commercial customers and is unlawful. Management estimates that the adverse effect of a decision to reduce the PTB rates for the period prior to the sale of the AEP REPs is approximately $11 million pretax. The District Court decision was appealed to the Third Court of Appeals by TCC and other parties. Based on advice of counsel, management believes that it will ultimately prevail on appeal. If the District Court’s decision is ultimately upheld on appeal or the Court of Appeals reverses the District Court on issues adverse to TCC, it could have an adverse effect on future results of operations and cash flows.

TCC and TNC ERCOT Price-to-Beat (PTB) Fuel Factor Appeal

Several parties including the Office of Public Utility Counsel 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. In June 2003, the Court ruled that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The amount of unaccounted for energy built into the PTB fuel factors was approximately $3 million for Mutual Energy WTU. The Court upheld the initial PTB orders on all other issues. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. Management believes, based on the advice of counsel, that the PUCT’s original decision will ultimately be upheld. If the court’s decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in the years 2002 through 2004 resulting in an adverse effect on TCC’s and TNC’s future results of operations and cash flows.

PSO Rate Review

PSO is involved in a commission staff-initiated rate review before the OCC. In that proceeding, PSO made a filing seeking to increase its base rates, while various other parties made recommendations to reduce PSO’s base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. Pending approval by the OCC, the settlement provides for a $7 million base rate reduction partially offset by a $6 million reduction in annual depreciation expense. The settlement also provides for recovery of $9 million of deferred fuel and the continuation of the vegetation management rider. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC did not approve the settlement in time for implementation of new base rates in May 2005 as agreed to by the parties, which voids the settlement. The OCC issued an Order approving the stipulation on May 2, 2005 with one exception. The Order approves the implementation of new base rates in June 2005 versus the stipulation date of May 2005.
 
RTO Formation/Integration

Prior to joining PJM, the AEP East companies deferred costs incurred under FERC orders to originally form a new RTO, (the Alliance) and subsequently to join an existing RTO (PJM). In 2004, we requested permission to amortize beginning January 1, 2005 the $18 million of deferred non-PJM billed formation/integration costs over 15 years and the $17 million of deferred PJM-billed integration costs, but we did not propose an amortization period for the PJM-billed costs in the application. The FERC has approved our application.

In January 2005, the AEP East companies began amortizing their deferred non-PJM billed costs over 15 years and the deferred PJM-billed integration costs over 10 years. The total amortization related to such costs was $1 million in the first quarter of 2005. As of March 31, 2005, the AEP East Companies have $34 million of deferred unamortized RTO formation/integration costs.

On March 8, 2005, we jointly filed with other utilities a request with the FERC to recover deferred PJM-billed integration costs of $17 million from all load-serving entities in the PJM RTO over a ten-year period starting January 1, 2005. On March 31, 2005, we also filed a request for a revised network integration transmission service revenue requirement for the AEP zone of PJM. Included in the costs reflected in that revenue requirement was the budgeted 2005 amortization of our deferred non-PJM billed Alliance RTO formation and PJM integration costs. The AEP East companies will be responsible for paying most of the amounts allocated by the FERC to the AEP East zone since the costs are attributable to their internal load.

Although several parties have filed protests of the joint filing to recover the deferred PJM-billed integration costs, we believe that it is probable that the FERC will ultimately approve recovery of the PJM-billed integration costs through the PJM OATT and that the FERC will grant a long enough amortization period to allow us to recover the deferred non-PJM billed Alliance RTO formation and PJM integration costs in the AEP East retail jurisdictions. If the FERC issues an adverse ruling, future results of operations and cash flows could be adversely affected.

FERC Order on Regional Through and Out Rates

A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. Billing statements from PJM for the first quarter of 2005 did not reflect any credits to AEP for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP accrued $26 million of SECA revenue in the first quarter of 2005 and has a receivable for SECA revenues of $37 million at March 31, 2005. SECA billings by PJM crediting AEP for their SECA revenue are scheduled to begin in May 2005 with retroactive adjustments to be billed by PJM in June and July 2005.

In a March 2005 FERC filing, we proposed an increase in the rate for network integration transmission service, as well as rates for other ancillary services. The primary customers of these services are the municipal and cooperative wholesale entities that have load delivery points in the AEP zone of PJM. As proposed, the rates will automatically increase to reflect the loss of SECA transition rates on April 1, 2006.

The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate was eliminated and replaced by SECA transition rates was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be sufficient to replace the SECA transition rate revenues and whether the new rates will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, if AEP zonal rates are not sufficiently increased by the FERC after March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.

Hold Harmless Proceeding

In a July 2002 order conditionally accepting our choice to join PJM, the FERC directed us, ComEd, MISO and PJM to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from us and ComEd joining PJM instead of MISO.

In July 2004, AEP and PJM filed jointly with the FERC a hold-harmless proposal. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. A hearing is scheduled for May 2005.

The Michigan and Wisconsin utilities have presented studies that show estimated adverse effects to utilities in the two states in the range of $60 million to $70 million over the term of the agreement for AEP and ComEd. The recent supplemental filing by the Michigan companies shows estimated adverse effects to utilities in Michigan of up to $50 million over the term of agreement. AEP and ComEd have presented studies that show no adverse effects to the Michigan and Wisconsin utilities. ComEd has separately settled this issue with the Michigan and Wisconsin utilities for a one time total payment of approximately $5 million, which was approved by the FERC. On December 27, 2004, AEP and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250,000 that was approved by the FERC on March 7, 2005. On April 25, 2005, AEP and International Transmission Company in Michigan filed a settlement that resolves all hold-harmless issues for a one-time payment of $120,000. Settlement negotiations are in progress with the remaining Michigan companies.

At this time, management is unable to predict the outcome of this proceeding. AEP will support vigorously its positions before the FERC. If the FERC ultimately approves a significant hold-harmless payment to the Michigan utilities, it would adversely impact results of operations and cash flows.
 
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

We are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in our 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring and update the 2004 Annual Report.

OHIO RESTRUCTURING

On January 26, 2005, the PUCO approved Rate Stabilization Plans for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for up to 4% of additional annual generation rate increases based on supporting the need for additional revenues. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. First quarter of 2005 pretax earnings were increased by $13 million for CSPCo and $32 million for OPCo as a result of implementing this provision of the Rate Stabilization Plans. Of these amounts approximately $8 million for CSPCo and $21 for OPCo relate to 2004 environmental carrying costs and RTO costs.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding their approval of the rate stabilization plans. On March 23, 2005, the PUCO denied all applications for rehearing. In April 2005, an intervenor filed an appeal to the Ohio Supreme Court. Management cannot predict the ultimate impact appeal proceedings will have on future results of operations and cash flows.

TEXAS RESTRUCTURING

The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items in TCC’s future true-up filing. TCC has asked permission from the PUCT to file its True-up Proceeding after the sales of its interest in STP have been concluded, with only the ownership interest in Oklaunion remaining to be settled. If the request is approved, it is anticipated that TCC’s True-up Proceeding will be filed during the second quarter of 2005 seeking recovery of its net regulatory asset of $1.6 billion for its net stranded cost and other true-up items, which it believes the Texas Restructuring Legislation allows.
 
The Components of TCC’s Net True-up Regulatory Asset as of March 31, 2005 and December 31, 2004 are:

   
TCC
 
   
March 31, 2005
 
December 31, 2004
 
   
(in millions)
 
Stranded Generation Plant Costs
 
$
898
 
$
897
 
Net Generation-related Regulatory Asset
   
249
   
249
 
Unrefunded Excess Earnings
   
(6
)
 
(10
)
Net Stranded Generation Costs
   
1,141
   
1,136
 
Carrying Costs on Stranded Generation Plant Costs
   
205
   
225
 
Net Stranded Generation Costs Designated for Securitization
   
1,346
   
1,361
 
               
Wholesale Capacity Auction True-up
   
483
   
483
 
Carrying Costs on Wholesale Capacity Auction True-up
   
91
   
77
 
Retail Clawback
   
(61
)
 
(61
)
Deferred Over-recovered Fuel Balance
   
(215
)
 
(212
)
Net Other Recoverable True-up Amounts
   
298
   
287
 
Total Recorded Net True-up Regulatory Asset
 
$
1,644
 
$
1,648
 

The Components of TNC’s Net True-up Regulatory Liability as of March 31, 2005 and December 31, 2004 are:

   
TNC
 
   
March 31, 2005
 
December 31, 2004
 
   
(in millions)
 
Retail Clawback
 
$
(14
)
$
(14
)
Deferred Over-recovered Fuel Balance
   
(5
)
 
(4
)
Total Recorded Net True-up Regulatory Liability
 
$
(19
)
$
(18
)

TCC Fuel Reconciliation

On April 14, 2005, the PUCT ruled that specific energy-only purchased power contracts included a capacity component which is not recoverable in fuel rates. In the first quarter of 2005, TCC recorded a provision for fuel revenue refund of $3 million, inclusive of interest, for this decision and continued to accrue interest on the deferred over-recovered fuel balance. This provision for refund results in a deferred over-recovery balance of $215 million as of March 31, 2005.

TCC Carrying Costs on Net True-up Regulatory Assets

TCC continues to accrue a carrying cost at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes (ADFIT) on TCC’s net stranded cost and other true-up items which was applied retroactively to January 1, 2004. In the first quarter of 2005, TCC accrued carrying costs of $21 million which was more than offset by an adjustment based on this order of $27 million. The net reduction of $6 million in carrying costs is included in Other Income in the first quarter of 2005 on the accompanying Consolidated Statements of Income.

As of March 31, 2005, TCC has computed carrying costs of $450 million of which $296 million was recognized as income in 2004 and the first quarter of 2005. The remaining equity component of the carrying costs of $154 million will be recognized in income as collected.
 
TCC Unrefunded Excess Earnings

At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. In the first quarter of 2005, TCC refunded an additional $4 million reducing its unrefunded excess earnings to $6 million.

TCC True-up Proceeding

When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated T&D rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

The nonaffiliated utility’s March order also provided for the present value of the cost free capital benefits of ADFIT associated with stranded generation costs to be offset against other recoverable true-up amounts when establishing the competition transition charges (CTC). TCC estimates its present value ADFIT benefit to be $212 million based on its current net true-up regulatory asset. TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT in the nonaffiliated utility’s order and determined that the projected cash flows from the transition charges were more than sufficient to recover TCC’s entire net true-up regulatory asset. As a result, no impairment has been recorded. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in its True-up Proceeding, TCC expects to amortize its total net true-up regulatory asset over recovery periods to be established by the PUCT in proceedings subsequent to TCC’s True-up Proceeding.

We believe that our recorded net true-up regulatory asset of $1.6 billion at March 31, 2005 is recoverable under the Texas Restructuring Legislation; however, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered. To the extent decisions of the PUCT in TCC’s future True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated companies, additional material disallowances and reductions of recorded carrying costs are possible, which could have a material adverse effect on future results of operations, cash flows and possibly financial condition.

TNC True-Up Proceeding

In January 2005, intervenors made various recommendations including an increase in excess earnings of $5 million and a T&D rate reduction of $3 million annually. The intervenors also recommended that TNC’s fuel over-recovery should be increased by $2 million. TNC is awaiting a PUCT decision and order and has recorded no disallowances based on intervenor contentions.

In 2004, TNC appealed to the state and federal courts the PUCT’s order in its final fuel reconciliation covering the period from July 2000 through December 31, 2001. In March 2005, the ALJ made certain recommendations regarding the deferred fuel balance resulting in an additional provision for refund of $1 million, which results in an over-recovery amount of $5 million. TNC will pursue vigorously its appeals, but cannot predict their outcome.
 
5. COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within our 2004 Annual Report, we continue to be involved in various legal matters. The 2004 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since our disclosure in the 2004 Annual Report. The matters discussed in the 2004 Annual Report without significant changes in status since year-end include, but are not limited to, (1) carbon dioxide public nuisance claims, (2) nuclear matters, (3) construction commitments, (4) potential uninsured losses, (5) shareholder lawsuits, (6) coal transportation dispute, (7) Bank of Montreal Claim and (8) FERC long-term contracts. See disclosure below for significant matters with changes in status subsequent to the disclosure made in our 2004 Annual Report.
 
Environmental

Federal EPA Complaint and Notice of Violation

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period.

Under the CAA, 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 CAA 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.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaint and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern states each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. These complaints have been assigned to the same judge in the Southern District Court. AEP filed an answer to the complaint in January 2005, denying the allegations and stating its defenses.

In August 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, a nonaffiliated 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 nonroutine 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 settlement between Ohio Edison, the Federal EPA and other parties to the litigation will avoid further litigation and result in expenditures at its plant.

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.

In August 2003, the District Court for the Middle District of South Carolina issued a decision in a case pending against Duke Energy Corporation, a nonaffiliated utility. The District Court 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. The Federal EPA requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals. The District Court denied the Federal EPA’s motion. In April 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that eliminated the need for a trial, but preserving plaintiffs’ right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. The United States subsequently filed a notice of appeal to the Fourth Circuit Court of Appeals. The case is fully briefed and oral argument was heard in February 2005.

In June 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 (TVA) for alleged CAA 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 CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court and on May 3, 2004, that petition was denied.

In June 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which our subsidiaries are members, to reopen petitions for review of the 1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA claims in our case and other related cases. On August 4, 2003, UARG filed a motion to separate and expedite review of their challenges to the 1980 and 1992 rulemakings from other unrelated claims in the consolidated appeal. The Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit Court could significantly impact further proceedings in our case. Briefing continues in this case and oral argument was held in January 2005.

In December 2000, Cinergy Corp., a nonaffiliated 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.

In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power & Light Company in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio state implementation plan occurred at the J.M. Stuart Station, and seeking injunctive relief and civil penalties. CSPCo owns a 26% share of the J.M. Stuart Station. The owners have filed a motion to dismiss portions of the complaint, based primarily upon the federal statute of limitations. In March 2005, in an unrelated case alleging new source review permitting claims against TVA, the court granted a motion to dismiss the claims against TVA on similar grounds. The owners have advised the court of this new decision. We believe the allegations in the complaint are without merit, and intend to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

We are unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If 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.
 
SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee and Pirkey plants. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo will file a response to the complaint in May 2005.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of $228,312 against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the references to a specific heat input value for each Welsh unit.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of $5,550 against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, financial condition or cash flows.

Operational

Power Generation Facility

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to us. We have subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 270 MW). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo has also agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.) (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000, (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) has provided a limited guaranty.

In November 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted AEP partial summary judgment on this issue, holding that the absence of operating protocols does not prevent enforcement of the PPA.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for these electric power products under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM, and SUEZ-TRACTEBEL S.A. under the guaranty, damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005.

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.
 
On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and will file a petition for review of this Initial Decision. The SEC will review the Initial Decision.
 
Enron Bankruptcy  

In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain of our subsidiaries had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - Right to use of cushion gas agreements - In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in state court of Texas seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to defend vigorously against BOA’s claims.

In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel reservoir and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA objected to the Magistrate Judge’s decision. On April 6, 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. We have objected to Enron’s attempted rejection of these agreements and have filed an adversary proceeding contesting Enron’s right to reject these agreements.

In January 2005, we sold a 98% limited partner interest in HPL. We have indemnified the buyer of the 98% interest in HPL against any damages resulting from the BOA litigation up to the purchase price. The determination of the gain on sale and the recognition of the gain is dependent on the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter.

Enron Bankruptcy - Commodity trading settlement disputes - 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 in connection with gas-related trading transactions. We asserted our right to offset trading payables owed to various Enron entities against trading receivables due to several of our subsidiaries. The parties are currently in nonbinding, court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding, court-sponsored mediation.

Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy 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. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.

Natural Gas Markets Lawsuits

In November 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. 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. Since then, a number of cases have been filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. In some of these cases, AEP (or a subsidiary) is among the companies named as defendants. These cases are at various pre-trial stages. Several of these cases had been transferred to the United States District Court for the District of Nevada but were subsequently remanded to California state court. In April 2005, the judge in Nevada dismissed one of the remaining cases in which AEP was a defendant on the basis of the filed rate doctrine. We will continue to defend vigorously each case where an AEP company is 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. Thereafter, two similar actions were filed in the same court against a number of companies including AEP and AEPES making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. On December 5, 2003, the Court issued its initial Pretrial Order consolidating all related cases, appointing co-lead counsel and providing for the filing of an amended consolidated complaint. In January 2004, plaintiffs filed an amended consolidated complaint. The defendants filed a motion to dismiss the complaint which the Court denied in September 2004. Plaintiffs have filed a Motion for Class Certification. The defendants, including AEP and AEPES, filed their opposition to class certification on April 8, 2005. Briefing on the issue of class certification is expected to be completed in the second quarter of 2005. Discovery is continuing in the case with a discovery cut-off date of June 30, 2005. We intend to defend vigorously against these claims.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP), filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against us and four of our subsidiaries, certain nonaffiliated 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. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, sought leave to intervene as plaintiffs asserting similar claims. We filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit. In April 2005, the defendants filed a Motion to Stay this case, pending the outcome of the appeal in the TCE case.
 
6. GUARANTEES

There are certain immaterial liabilities recorded for guarantees entered into subsequent to December 31, 2002 in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

LETTERS OF CREDIT

We have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. We issued all of these LOCs in our ordinary course of business. At March 31, 2005, the maximum future payments for all the LOCs were approximately $234 million with maturities ranging from May 2005 to April 2007. As the parent of the various subsidiaries that have issued these LOCs, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these LOCs are drawn.

GUARANTEES OF THIRD-PARTY OBLIGATIONS

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 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 $51 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 March 31, 2005, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

INDEMNIFICATIONS AND OTHER GUARANTEES

Contracts

We entered into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. We cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events. In 2004 and the first three months of 2005, we entered into several sale agreements. An update of the status of sales agreements is discussed in Note 7. These sale agreements include indemnifications with a maximum exposure of approximately $1.9 billion. There are no material liabilities recorded for any indemnifications.

Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At March 31, 2005, the maximum potential loss for this lease agreement was approximately $43 million ($28 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms, for a maximum of twenty years. We intend to renew the lease for the full twenty years.

At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years, (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value, or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. This operating lease agreement allows us to avoid a large initial capital expenditure, and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the term from approximately 86% to 77% of the projected fair market value of the equipment. At March 31, 2005, the maximum potential loss was approximately $31 million ($20 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. The railcars are subleased for one year terms to a nonaffiliated company under an operating lease. The sublessee may renew the lease for up to three additional one-year terms. AEP has other railcar lease arrangements that do not utilize this type of structure.

7. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

DISPOSITIONS COMPLETED AND ANTICIPATED BEING COMPLETED DURING THE FIRST HALF OF 2005

Houston Pipe Line Company (Investments - Gas Operations segment)

In January 2005, we sold a 98% controlling interest in HPL, 30 BCF of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. We retained a 2% ownership interest in HPL and provide certain transitional administrative services to the buyer. Although the assets have been legally transferred, it is not possible to determine all costs associated with the transfer until the BOA litigation is resolved. Accordingly, we have deferred the excess of the sales price over the carrying cost of the net assets transferred as a deferred gain of $407 million as of March 31, 2005, which is reflected in Deferred Credits and Other on our accompanying Consolidated Balance Sheets. We provided an indemnity in an amount up to the purchase price to the purchaser for damages, if any, arising from litigation with BOA and a resulting inability to use the cushion gas (see “Enron Bankruptcy - - Right to Use of Cushion Gas Agreements” section of Note 5). The HPL operations do not meet the criteria to be shown as discontinued operations due to continuing involvement associated with various contractual obligations. Significant continuing involvement includes cash flows from long-term gas contracts with the buyer through 2008, the cushion gas arrangement and our 2% ownership interest.

We also have a put option expiring in 2006, which allows us to sell our remaining 2% interest to the buyer for approximately $16 million.

Pacific Hydro Limited (Investments - Other segment)

In March 2005, we signed an agreement with Acciona, S.A. for the sale of our equity investment in Pacific Hydro Limited for approximately $83 million. The sale is contingent on Acciona obtaining a controlling interest in Pacific Hydro Limited. If the sale occurs, we will recognize an estimated pretax gain of approximately $50 million.

Texas REPs (Utility Operations segment)

In December 2002, we sold two of our Texas REPs to Centrica, a UK-based provider of retail energy. The sales price was $146 million plus certain other payments including an earnings-sharing mechanism (ESM) for AEP and Centrica to share in the earnings of the sold business for the years 2003 through 2006. The method of calculating the annual earnings-sharing amount was included in the Purchase and Sales Agreement.

There has been an ongoing dispute between AEP and Centrica related to the ESM calculation. In March 2005, AEP and Centrica entered into a series of agreements resulting in the resolution of open issues related to the sale and the disputed ESM payments for 2003 and 2004. Also in March 2005, we received payments of $45 million and $70 million related to the ESM payments for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in the first quarter of 2005, which is reflected in Other Income on our accompanying Consolidated Statements of Income. The ESM payments for 2005 and 2006 are contingent on Centrica’s future operating results and are capped at $70 million and $20 million, respectively. Any shortfall below the potential $70 million for 2005 will be added to the 2006 cap.

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In January 2004, we signed an agreement to sell TCC’s 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to an unrelated party. By May 2004, we received notice from the two nonaffiliated co-owners of the Oklaunion Power Station, announcing their decision to exercise their right of first refusal, with terms similar to the original agreement. In June 2004 and September 2004, we entered into sales agreements with both of our nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. These agreements are currently being challenged in Dallas County, Texas State District Court by the unrelated party with which we entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. We cannot predict when these issues will be resolved. We do not expect the sale to have a significant effect on our future results of operations. TCC’s assets and liabilities related to the Oklaunion Power Station have been classified as Assets Held for Sale and Liabilities Held for Sale, respectively, in our Consolidated Balance Sheets at March 31, 2005 and December 31, 2004.

Texas Plants - South Texas Project (Utility Operations segment)

In February 2004, we signed an agreement to sell TCC’s 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, we received notice from co-owners of their decisions to exercise their rights of first refusal, with terms similar to the original agreement. In September 2004, we entered into sales agreements with two of our nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. We do not expect the sale to have a significant effect on our future results of operations. We expect the sale to close in the second quarter of 2005. TCC’s assets and liabilities related to STP have been classified as Assets Held for Sale and Liabilities Held for Sale, respectively, in our Consolidated Balance Sheets at March 31, 2005 and December 31, 2004.

DISCONTINUED OPERATIONS

Certain of our operations were determined to be discontinued operations and have been classified as such for all periods presented. Results of operations of these businesses have been reclassified for the three-month periods ended March 31, 2005 and 2004 as shown in the following table:

   
SEEBOARD (a)
 
U.K. Operations (b)
 
Total
 
2005 Revenue
 
$
-
 
$
-
 
$
-
 
2005 Pretax Income (Loss)
   
-
   
(8
)
 
(8
)
2005 Income (Loss) After tax
   
6
   
(5
)
 
1
 

   
Pushan Power Plant
 
LIG (c)
 
U.K. Operations
 
Total
 
2004 Revenue
 
$
10
 
$
160
 
$
41
 
$
211
 
2004 Pretax Income (Loss)
   
-
   
(1
)
 
(19
)
 
(20
)
2004 Income (Loss) After tax
   
6
   
(1
)
 
(12
)
 
(7
)

            (a) Includes a tax adjustment related to the sale of SEEBOARD.
            (b) Relates primarily to purchase price true-up adjustments.
            (c) Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub LLC.

During the quarter ended March 31, 2004, the net increase in cash and cash equivalents of discontinued operations was $24 million, primarily from the cash flows from operating activities of the discontinued operations.
 
ASSETS HELD FOR SALE

The assets and liabilities of the entities that were classified as held for sale at March 31, 2005 and December 31, 2004 are as follows:

   
Texas Plants
 
   
March 31, 2005
 
December 31, 2004
 
Assets:
 
(in millions)
Other Current Assets
 
$
25
 
$
24
 
Property, Plant and Equipment, Net
   
416
   
413
 
Regulatory Assets
   
52
   
48
 
Nuclear Decommissioning Trust Fund
   
143
   
143
 
Total Assets Held for Sale
 
$
636
 
$
628
 
               
Liabilities:
             
Regulatory Liabilities
 
$
1
 
$
1
 
Asset Retirement Obligations
   
254
   
249
 
Total Liabilities Held for Sale
 
$
255
 
$
250
 
 
8. BENEFIT PLANS 

Components of Net Periodic Benefit Costs

The following table provides the components of our net periodic benefit cost for the following plans for the three months ended March 31, 2005 and 2004:

   
Pension Plans
 
Other Postretirement Benefit Plans
 
   
2005
 
2004
 
2005
 
2004
 
   
(in millions)
 
Service Cost
 
$
23
 
$
22
 
$
11
 
$
10
 
Interest Cost
   
56
   
56
   
27
   
29
 
Expected Return on Plan Assets
   
(77
)
 
(72
)
 
(23
)
 
(20
)
Amortization of Transition (Asset) Obligation
   
-
   
-
   
7
   
7
 
Amortization of Net Actuarial Loss
   
13
   
4
   
7
   
9
 
Net Periodic Benefit Cost
 
$
15
 
$
10
 
$
29
 
$
35
 
 
 
9. BUSINESS SEGMENTS

Our segments and their related business activities are as follows:

Utility Operations

·
Domestic generation of electricity for sale to retail and wholesale customers.
·
Domestic electricity transmission and distribution.

Investments - - Gas Operations (a)

·
Gas pipeline and storage services.
·
Gas marketing and risk management activities.
 
Investments - - UK Operations (b)

·
International generation of electricity for sale to wholesale customers.
·
Coal procurement and transportation to our plants.

Investments - - Other (c)

·
Bulk commodity barging operations, wind farms, independent power producers and other energy supply related businesses.

(a)
Operations of Louisiana Intrastate Gas, including Jefferson Island Storage, were classified as Discontinued Operations during 2003 and were sold during the third and fourth quarter of 2004, respectively. A ninety-eight percent interest in HPL was sold during the first quarter of 2005.
(b)
UK Operations were classified as Discontinued Operations during 2003 and were sold during the third quarter of 2004.
(c)
Four independent power producers were sold during the third and fourth quarters of 2004.
 
With the sale of HPL during January 2005, we have substantially completed planned disposals of all significant non-core assets. Accordingly, effective with the quarter ended March 31, 2005, certain subsidiaries representing shared service functions and costs were reclassified to Utility Operations and Investments - Other from either Investments - Other or All Other. Such reclassifications were deemed necessary given the remaining compositions of the individual segments and the nature of the shared service functions and costs. The 2004 information presented herein has been reclassified to conform to the 2005 presentation.
 
The tables below present segment income statement information for the three months ended March 31, 2005 and 2004 and balance sheet information as of March 31, 2005 and December 31, 2004. These amounts include certain estimates and allocations where necessary. Prior year amounts have been reclassified to conform to the current year’s presentation.


        
Investments
                
Three Months Ended
 
Utility Operations
 
Gas Operations
 
UK Operations
 
Other
 
All Other (a)
 
Reconciling Adjustments (b)
 
Consolidated
 
March 31, 2005
 
(in millions)
 
Revenues from:
                                             
External Customers
 
$
2,537
 
$
357
 
$
-
   
$
89
 
$
-
 
$
-
 
$
2,983
 
Other Operating Segments
   
77
   
(73
)
 
-
     
3
   
1
   
(8
)
 
-
 
Total Revenues
 
$
2,614
 
$
284
 
$
-
   
$
92
 
$
1
 
$
(8
)
$
2,983
 
                                               
Income (Loss) Before Discontinued   Operations
 
$
353
 
$
10
 
$
-
   
$
5
 
$
(14
)
$
-
 
$
354
 
Discontinued Operations, Net of Tax
   
-
   
-
   
(5
)
   
6
   
-
   
-
   
1
 
Net Income (Loss)
 
$
353
 
$
10
 
$
(5
)
 
$
11
 
$
(14
)
$
-
 
$
355
 
                                               
As of March 31, 2005
                                             
Total Property, Plant and Equipment
 
$
36,348
 
$
2
 
$
-
   
$
835
 
$
3
 
$
-
 
$
37,188
 
Accumulated Depreciation and   Amortization
   
14,494
   
1
   
-
     
93
   
1
   
-
   
14,589
 
Total Property, Plant and Equipment -   Net
 
$
21,854
 
$
1
 
$
-
   
$
742
 
$
2
 
$
-
 
$
22,599
 
                                               
Total Assets
 
$
32,655
 
$
1,295
 
$
597
 (c)
 
$
1,557
 
$
10,740
 
$
(11,747
)
$
35,097
 
Assets Held for Sale
   
636
   
-
   
-
     
-
   
-
   
-
   
636
 
 
(a)
All Other includes interest, litigation and other miscellaneous parent company expenses.
(b)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.
(c)
Total Assets of $597 million for the Investments-UK Operations segment include $551 million in affiliated accounts receivable that are eliminated in consolidation. The majority of the remaining $46 million in assets represents cash equivalents along with value-added tax receivables.
 
 
        
Investments
                
Three Months Ended
 
Utility Operations
 
Gas Operations
 
UK Operations
 
Other
 
All Other (a)
 
Reconciling Adjustments (b)
 
Consolidated
 
March 31, 2004
 
(in millions)
 
Revenues from:
                                             
External Customers
 
$
2,581
 
$
652
 
$
-
   
$
131
 
$
-
 
$
-
 
$
3,364
 
Other Operating Segments
   
21
   
24
   
-
     
16
   
6
   
(67
)
 
-
 
Total Revenues
 
$
2,602
 
$
676
 
$
-
   
$
147
 
$
6
 
$
(67
)
$
3,364
 
                                               
Income (Loss) Before Discontinued
  Operations
 
$
304
 
$
(10
)
$
-
   
$
4
 
$
(9
)
$
-
 
$
289
 
Discontinued Operations, Net of Tax
   
-
   
(1
)
 
(12
)
   
6
   
-
   
-
   
(7
)
Net Income (Loss)
 
$
304
 
$
(11
)
$
(12
)
 
$
10
 
$
(9
)
$
-
 
$
282
 
                                               
As of December 31, 2004
                                             
Total Property, Plant and Equipment
 
$
36,006
 
$
445
 
$
-
   
$
832
 
$
3
 
$
-
 
$
37,286
 
Accumulated Depreciation and   Amortization
   
14,355
   
43
   
-
     
86
   
1
   
-
   
14,485
 
Total Property, Plant and Equipment -   Net
 
$
21,651
 
$
402
 
$
-
   
$
746
 
$
2
 
$
-
 
$
22,801
 
                                               
Total Assets
 
$
32,175
 
$
1,789
 
$
221
 (c)
 
$
2,071
 
$
8,093
 
$
(9,686
)
$
34,663
 
Assets Held for Sale
   
628
   
-
   
-
     
-
   
-
   
-
   
628
 

(a)
All Other includes interest, litigation and other miscellaneous parent company expenses.
(b)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.
(c)
Total Assets of $221 million for the Investments-UK Operations segment include $124 million in affiliated accounts receivable that are eliminated in consolidation. The majority of the remaining $97 million in assets represents cash equivalents and third party receivables.
 
10. FINANCING ACTIVITIES

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2005 are shown in the table below.

Company
 
Type of Debt
 
Principal Amount
   
Interest Rate
 
Due Date
 
       
(in millions)
           
Issuances:
                           
APCo
   
Senior Unsecured Notes
 
$
200
     
4.95%
 
 
2015
 
OPCo
   
Installment Purchase Contracts
   
164
     
Variable
   
2028
 
OPCo
   
Installment Purchase Contracts
   
54
     
Variable
   
2029
 
TCC
   
Installment Purchase Contracts
   
162
     
Variable
   
2030
 
Non-Registrant:
                           
AEP Subsidiary
   
Notes Payable
   
6
     
Variable
   
2009
 
Total Issuances
       
$
586
 (a)
             

(a)
Amount indicated on statement of cash flows of $580 million is net of issuance costs and unamortized premium or discount.
 
Company
 
Type of Debt
 
Principal Amount
   
Interest Rate
 
Due Date
 
       
(in millions)
           
Retirements and Principal Payments:
                           
AEP
   
Other Debt
 
$
3
     
Variable
   
2007
 
AEP and Subsidiaries
   
Other
   
6
 (b)
   
Variable
   
Various
 
OPCo
   
Installment Purchase Contracts
   
102
     
6.375%
 
 
2029
 
OPCo
   
Installment Purchase Contracts
   
80
     
Variable
   
2028
 
OPCo
   
Installment Purchase Contracts
   
36
     
Variable
   
2029
 
OPCo
   
Notes Payable
   
1
     
6.81%
 
 
2008
 
OPCo
   
Notes Payable
   
3
     
6.27%
 
 
2009
 
SWEPCo
   
Notes Payable
   
2
     
4.47%
 
 
2011
 
SWEPCo
   
Notes Payable
   
1
     
Variable
   
2008
 
TCC
   
Senior Unsecured Notes
   
150
     
3.00%
 
 
2005
 
TCC
   
Senior Unsecured Notes
   
100
     
Variable
   
2005
 
TCC
   
Securitization Bonds
   
29
     
3.54%
 
 
2005
 
Non-Registrant:
                           
AEP Subsidiary
   
Notes Payable
   
3
     
Variable
   
2017
 
Total Retirements
       
$
516
 (c)
           

(b)
Amount reflects mark-to-market of risk management contracts.
(c)
Amount indicated on statement of cash flows of $510 million does not include $6 million related to the mark-to-market of risk management contracts.

Preferred Stock Redemption

In January 2005, the following outstanding shares of preferred stock were redeemed:

Company
 
Series
 
Number of Shares Redeemed
 
Amount
 
           
(in millions)
 
I&M
   
5.900%
 
 
132,000
 
$
13
 
I&M
   
6.250%
 
 
192,500
   
19
 
I&M
   
6.875%
 
 
157,500
   
16
 
I&M
   
6.300%
 
 
132,450
   
13
 
OPCo
   
5.900%
 
 
  50,000
   
5
 
               
$
66
 

Common Stock Repurchase

In March 2005, we repurchased 12.5 million shares of our outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share plus transaction fees. The 12.5 million shares repurchased under the program are held in treasury and are subject to a future contingent purchase price adjustment based on the actual purchase prices paid for the common stock during the program period. Based on this adjustment, an asset of $2 million is reflected in Accounts Receivable on our Consolidated Balance Sheets as of March 31, 2005 due to the fact that the actual stock purchase prices were less than our initial payment.
 

 
AEP GENERATING COMPANY
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 






AEP GENERATING COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Operating revenues are derived from the sale of our share of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for a FERC approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Fluctuations in Net Income are a result of terms in the unit power agreements which allow for the calculation of return on total capital monthly.

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
1.8
 
               
Change in Gross Margin:
             
Wholesale Sales
         
(2.5
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
3.8
       
Depreciation and Amortization
   
(0.2
)
     
Taxes Other Than Income Taxes
   
(0.1
)
     
Interest Charges
   
(0.1
)
     
Total Change in Operating Expenses and Other
         
3.4
 
               
Income Tax Expense
         
(0.2
)
               
First Quarter of 2005 Net Income
       
$
2.5
 

Gross Margin decreased $2.5 million primarily due to a decrease in operation and maintenance expense. Gross Margin fluctuates consistent with operation and maintenance expense in accordance with the unit power agreements.

The decrease in Other Operation and Maintenance expenses resulted from decreased outages and the related costs compared to prior year. In 2004, Rockport Plant Unit 2 was shutdown for planned boiler inspection and repairs from early February through the end of the quarter.

Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were 1.8% and (9.5)%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is primarily due to amortization of investment tax credits, flow-through of book versus tax temporary differences and state income taxes. The increase in the effective tax rate is primarily due to higher pretax income in 2005.

Off-Balance Sheet Arrangement

In prior years, we entered into an off-balance sheet arrangement. Our current policy restricts the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements. Our off-balance sheet arrangement has not changed significantly since year-end. For complete information on our off-balance sheet arrangement see “Off-balance Sheet Arrangements” in the “Management’s Narrative Discussion and Analysis” section of our 2004 Annual Report.
 
Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and the impact of new accounting pronouncements.

 

 

AEP GENERATING COMPANY
STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
           
OPERATING REVENUES
 
$
66,546
 
$
55,282
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
35,135
   
21,398
 
Rent - Rockport Plant Unit 2
   
17,071
   
17,071
 
Other Operation
   
2,385
   
2,490
 
Maintenance
   
1,718
   
5,400
 
Depreciation and Amortization
   
5,956
   
5,734
 
Taxes Other Than Income Taxes
   
1,024
   
944
 
Income Taxes
   
936
   
698
 
TOTAL
   
64,225
   
53,735
 
               
OPERATING INCOME
   
2,321
   
1,547
 
               
Nonoperating Income
   
-
   
24
 
Nonoperating Expenses
   
64
   
69
 
Nonoperating Income Tax Credit
   
891
   
857
 
Interest Charges
   
632
   
532
 
               
NET INCOME
 
$
2,516
 
$
1,827
 
               

STATEMENTS OF RETAINED EARNINGS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
           
BALANCE AT BEGINNING OF PERIOD
 
$
24,237
 
$
21,441
 
               
Net Income
   
2,516
   
1,827
 
               
Cash Dividends Declared
   
940
   
1,262
 
               
BALANCE AT END OF PERIOD
 
$
25,813
 
$
22,006
 

The common stock of AEGCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.


 


AEP GENERATING COMPANY
BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
682,162
 
$
681,254
 
General
   
3,923
   
3,739
 
Construction Work in Progress
   
6,990
   
7,729
 
Total
   
693,075
   
692,722
 
Accumulated Depreciation and Amortization
   
373,165
   
368,484
 
TOTAL - NET
   
319,910
   
324,238
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
119
   
119
 
               
CURRENT ASSETS
             
Accounts Receivable - Affiliated Companies
   
24,248
   
23,078
 
Fuel
   
10,613
   
16,404
 
Materials and Supplies
   
6,337
   
5,962
 
Prepayments
   
35
   
-
 
TOTAL
   
41,233
   
45,444
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
Unamortized Loss on Reacquired Debt
   
4,437
   
4,496
 
Asset Retirement Obligations
   
1,165
   
1,117
 
Deferred Property Taxes
   
3,441
   
557
 
Other Deferred Charges
   
417
   
422
 
TOTAL
   
9,460
   
6,592
 
               
TOTAL ASSETS
 
$
370,722
 
$
376,393
 

See Notes to Financial Statements of Registrant Subsidiaries.

 


AEP GENERATING COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
Common Shareholder’s Equity:
             
Common Stock - $1,000 par value per share:
             
Authorized and Outstanding - 1,000 shares
 
$
1,000
 
$
1,000
 
Paid-in Capital
   
23,434
   
23,434
 
Retained Earnings
   
25,813
   
24,237
 
Total Common Shareholder’s Equity
   
50,247
   
48,671
 
Long-term Debt
   
44,822
   
44,820
 
TOTAL
   
95,069
   
93,491
 
               
CURRENT LIABILITIES
             
Advances from Affiliates
   
7,131
   
26,915
 
Accounts Payable:
             
General
   
990
   
443
 
Affiliated Companies
   
14,405
   
17,905
 
Taxes Accrued
   
9,165
   
8,806
 
Interest Accrued
   
456
   
911
 
Obligations Under Capital Leases
   
285
   
210
 
Rent Accrued - Rockport Plant Unit 2
   
23,427
   
4,963
 
Other
   
102
   
73
 
TOTAL
   
55,961
   
60,226
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
23,687
   
24,762
 
Regulatory Liabilities:
             
Asset Removal Costs
   
25,965
   
25,428
 
Deferred Investment Tax Credits
   
45,416
   
46,250
 
SFAS 109 Regulatory Liability, Net
   
12,735
   
12,852
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
   
98,512
   
99,904
 
Obligations Under Capital Leases
   
12,137
   
12,264
 
Asset Retirement Obligations
   
1,240
   
1,216
 
TOTAL
   
219,692
   
222,676
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
370,722
 
$
376,393
 

See Notes to Financial Statements of Registrant Subsidiaries.

 


AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
2,516
 
$
1,827
 
Adjustments to Reconcile Net Income to Net Cash Flows  From Operating Activities:
             
Depreciation and Amortization
   
5,956
   
5,734
 
Deferred Income Taxes
   
(1,192
)
 
(656
)
Deferred Investment Tax Credits
   
(834
)
 
(834
)
Deferred Property Taxes
   
(2,884
)
 
(2,439
)
Amortization of Deferred Gain on Sale and Leaseback -   Rockport Plant Unit 2
   
(1,392
)
 
(1,392
)
Change in Other Noncurrent Assets
   
(233
)
 
91
 
Change in Other Noncurrent Liabilities
   
436
   
(156
)
Changes in Components of Working Capital:
             
Accounts Receivable
   
(1,170
)
 
7,145
 
Fuel, Materials and Supplies
   
5,416
   
(3,687
)
Accounts Payable
   
(2,953
)
 
(243
)
Taxes Accrued
   
359
   
4,539
 
Interest Accrued
   
(455
)
 
(455
)
Rent Accrued - Rockport Plant Unit 2
   
18,464
   
18,464
 
Other Current Assets
   
(35
)
 
(32
)
Other Current Liabilities
   
104
   
28
 
Net Cash Flows From Operating Activities
   
22,103
   
27,934
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(1,379
)
 
(7,525
)
Net Cash Flows Used For Investing Activities
   
(1,379
)
 
(7,525
)
               
FINANCING ACTIVITIES
             
Changes in Advances from Affiliates, Net
   
(19,784
)
 
(19,147
)
Dividends Paid
   
(940
)
 
(1,262
)
Net Cash Flows Used For Financing Activities
   
(20,724
)
 
(20,409
)
               
Net Increase in Cash and Cash Equivalents
   
-
   
-
 
Cash and Cash Equivalents at Beginning of Period
   
-
   
-
 
Cash and Cash Equivalents at End of Period
 
$
-
 
$
-
 

SUPPLEMENTAL DISCLOSURE:
     
Cash paid (received) for interest net of capitalized amounts was $1,021,000 and $921,000 and for income taxes was $5,439,000 and $(218,000) in 2005 and 2004, respectively.

See Notes to Financial Statements of Registrant Subsidiaries.

 


AEP GENERATING COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to AEGCo’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to AEGCo. 

   
Footnote
Reference
 
       
Significant Accounting Matters
 
 Note 1
 
New Accounting Pronouncements
 
 Note 2
 
Commitments and Contingencies
 
 Note 5
 
Guarantees
 
 Note 6
 
Business Segments
 
 Note 9
 
Financing Activities
 
 Note 10
 


 


 
 
 
 
 
 
 
 
 
 
 

 

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
 
Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
29
 
               
Changes in Gross Margin:
             
Texas Wires
   
2
       
Texas Supply
   
(35
)
     
Off-system Sales
   
(2
)
     
Other Revenues
   
(9
)
     
Total Change in Gross Margin
         
(44
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
8
       
Nonoperating Income and Expense, Net
   
(11
)
     
Interest Charges
   
6
       
Total Change in Operating Expenses and Other
         
3
 
               
Income Tax Expense
         
13
 
               
First Quarter of 2005 Net Income
       
$
1
 

Net Income decreased $28 million to $1 million in the first quarter of 2005. The key drivers of the decrease were a $44 million decrease in gross margin partially offset by a net decrease in Other Operation and Maintenance of $8 million and by a $13 million decrease in Income Tax Expense.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Texas Supply margins were $35 million less than the prior period primarily due to the loss of our largest REP customer of $77 million and loss of ERCOT reliability-must-run margins of $6 million and capacity sales of $9 million due to the sale of certain generation plants in the third quarter of 2004, offset by lower fuel expense of $57 million.
·
Other Revenues for 2005 decreased $9 million in comparison to 2004 primarily due to a prior year unfavorable adjustment for affiliated OATT and ancillary services resulting from revised ERCOT data received for the years 2001 through 2003.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $8 million primarily due to a decrease in production plant operations and maintenance expenses as a result of the sale of certain generation plants in the third quarter of 2004.
·
Nonoperating Income and Expense, Net decreased partially due to carrying costs on stranded cost recovery of $21 million recorded in the first quarter of 2005, offset by an adjustment of $27 million. The adjustment relates to a nonaffiliated utility’s securitization proceeding where the PUCT issued an order in March 2005 that resulted in a reduction in the nonaffiliated utility’s carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes retroactive to January 1, 2004.
·
In addition, Nonoperating Income and Expense, Net decreased $6 million partially due to the absence of risk management activities in the first quarter of 2005.
·
Interest Charges decreased $6 million primarily due to the defeasance of $112 million of First Mortgage Bonds in 2004 and the resultant deferral of the interest cost as a regulatory asset related to the cost of the sale of generation assets, the redemption of the 8% Notes Payable to Trust, long-term debt maturities and other financing activities.

Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were (906.2)% and 29.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from parent, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is primarily due to lower pretax income in 2005, federal income tax adjustments and consolidated tax savings from parent, offset in part by a decrease in state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Our current ratings are as follows:

   
Moody’s
 
S&P
 
Fitch
 
               
First Mortgage Bonds
   
Baa1
   
BBB
   
A
 
Senior Unsecured Debt
   
Baa2
   
BBB
   
A-
 

Cash Flow

Cash flows for the three months ended March 31, 2005 and 2004 were as follows:

   
2005
 
2004
 
   
(in thousands)
 
Cash and cash equivalents at beginning of period
 
$
-
 
$
760
 
Cash flows from (used for):
             
Operating activities
   
(121,316
)
 
25,873
 
Investing activities
   
3,997
   
4,582
 
Financing activities
   
118,292
   
(29,182
)
Net increase in cash and cash equivalents
   
973
   
1,273
 
Cash and cash equivalents at end of period
 
$
973
 
$
2,033
 

Operating Activities

Our net cash flows used for operating activities were $121 million for the first three months of 2005. We produced income of $1 million during the period including noncash expense items of $29 million for Depreciation and Amortization and $(30) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relate to a number of items; the most significant are decreases in Accounts Payable, Taxes Accrued and Interest Accrued offset in part by an increase in Accounts Receivable, Net. Accounts Payable decreased $41 million primarily due to lower vendor related payables and lower third party energy transactions. Taxes Accrued decreased $118 million primarily due to a Federal income tax payment offset by the annual tax accruals related to 2005 property taxes. Interest Accrued decreased $22 million primarily due to interest payments on debentures and senior unsecured notes offset by monthly accruals.

Our net cash flows from operating activities were $26 million for the first three months of 2004. We produced income of $29 million during the period including noncash expense items of $29 million for Depreciation and Amortization and $(34) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in these asset and liability accounts relates to a number of items; the most significant is an increase in Taxes Accrued offset by decreases in Accounts Payable and Interest Accrued. Taxes Accrued increased $32 million primarily due to the annual tax accruals related to property taxes net of a payment in 2004 and by a decrease in Federal income tax refunds. Accounts Payable decreased $14 million primarily due to decreased trading related payables and fewer fuel related shipments. Interest Accrued decreased $20 million primarily due to interest payments on debentures and senior unsecured notes offset by monthly accruals.

Investing Activities

Cash Flows From Investing Activities were $4 million in 2005 primarily due to a decrease of $32 million in Other Cash Deposits, Net related to principal payments on transition funding bonds offset by Construction Expenditures of $28 million related to projects for improved transmission and distribution service reliability. For the remainder of 2005, we expect our Construction Expenditures to be approximately $180 million.

Cash Flows From Investing Activities were $5 million in 2004 primarily due to a decrease of $28 million in Other Cash Deposits, Net related to principal payments on transition funding bonds offset by Construction Expenditures of $24 million related to projects for improved transmission and distribution service reliability.

Financing Activities

Cash Flows From Financing Activities of $118 million in 2005 were due to a $238 million increase in Advances to/from Affiliates, Net and issuances of Installment Purchase Contracts of $159 million offset by retirements of Senior Unsecured Note Payables and Securitization Bonds of $279 million.

Cash Flows Used for Financing Activities of $29 million in 2004 were due to retirements of long-term debt, payment of dividends and increased Advances to Affiliates.

Financing Activity

Long-term debt issuances and retirements during the first three months of 2005 were:

Issuances

   
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount
 
Rate
 
Date
 
   
(in thousands)
 
(%)
     
Installment Purchase Contract
 
$
111,700
   
Variable
   
2030
 
Installment Purchase Contract
   
  50,000
   
Variable
   
2030
 
                     

Retirements

   
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount
 
Rate
 
Date
 
   
(in thousands)
 
(%)
     
Senior Unsecured Note Payable
 
$
150,000
   
3.00
   
2005
 
Senior Unsecured Note Payable
   
100,000
   
Variable
   
2005
 
Securitization Bonds
   
  29,386
   
3.54
   
2005
 
 
Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity. Finally, we expect to receive asset sale proceeds of approximately $333 million in the first half of 2005, subject to resolution of the rights of first refusal issues and obtaining the necessary regulatory approvals.

Significant Factors

Texas Restructuring

The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of our net stranded generation costs and other recoverable true-up items in our future true-up filing. We have asked permission from the PUCT to file our True-up Proceeding after the sales of our interest in STP have been concluded. If the request is approved, it is anticipated that our True-up Proceeding will be filed during the second quarter of 2005 seeking recovery of our net regulatory asset of $1.6 billion for our net stranded cost and other true-up items which we believe the Texas Restructuring Legislation allows.

We continue to accrue a carrying cost at the embedded 8.12% debt component rate and will continue to do so until we recover our approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 further clarifying how the amounts are to be calculated. This resulted in a reduction in our accrued carrying costs based on the methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes (ADFIT) on our net stranded cost and other true-up items retroactive to January 1, 2004. In the first quarter of 2005, we accrued carrying costs of $21 million, which was more than offset by an adverse adjustment of $27 million based on this order. The net reduction of $6 million in carrying costs is included in Nonoperating Income in the first quarter of 2005 on our accompanying Consolidated Statements of Income.

As of March 31, 2005, we have computed carrying costs of $450 million of which $296 million was recognized as income in 2004 and the first quarter of 2005. The remaining equity component of the carrying cost of $154 million will be recognized in income as collected.

When the True-up Proceeding is completed, we intend to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated transmission and distribution rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

We believe that our recorded net true-up regulatory asset of $1.6 billion at March 31, 2005 is recoverable under the Texas Restructuring Legislation; however, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered. To the extent decisions of the PUCT in our future True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated companies, additional material disallowances and reductions of recorded carrying costs are possible, which could have a material adverse effect on our future results of operations, cash flows and possibly financial condition.

TCC Rate Case

We have an on-going transmission and distribution rate review before the PUCT. In that rate review, the PUCT has issued various decisions and conducted additional hearings in March 2005. At an open meeting on April 13, 2005, the PUCT decided all remaining issues except the amount of affiliate expenses to include in revenue requirements which the PUCT decided to defer. Adjusted for the decisions approved by the PUCT through April 13, 2005, the ALJ’s recommended disallowances of affiliate expenses would produce an annual rate reduction of $25 million to $52 million. If we were to prevail on the affiliate expenses issue, the result would be an annual rate increase of $2 million. An order reducing our rates could have an adverse effect on future results of operations and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
 
Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.


 


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
9,701
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(3,113
)
Fair Value of New Contracts When Entered During the Period (b)
   
33
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
(3,799
)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
-
 
Total MTM Risk Management Contract Net Assets
   
2,822
 
Net Cash Flow Hedge Contracts (f)
   
(4,221
)
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2005
 
$
(1,399
)

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
 
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Cash Flow Hedges
 
Total (b)
 
Current Assets
 
$
4,951
 
$
2,116
 
$
7,067
 
Noncurrent Assets
   
4,275
   
46
   
4,321
 
Total MTM Derivative Contract Assets
   
9,226
   
2,162
   
11,388
 
                     
Current Liabilities
   
(4,394
)
 
(6,269
)
 
(10,663
)
Noncurrent Liabilities
   
(2,010
)
 
(114
)
 
(2,124
)
Total MTM Derivative Contract Liabilities
   
(6,404
)
 
(6,383
)
 
(12,787
)
                     
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
2,822
 
$
(4,221
)
$
(1,399
)

(a)
Does not include Cash Flow Hedges.
(b)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009
 
Total (c)
 
Prices Actively Quoted - Exchange Traded Contracts
$
(609
)
$
234
 
$
485
 
$
-
 
$
-
 
$
-
 
$
110
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
1,185
   
1,006
   
740
   
317
   
-
   
-
   
3,248
 
Prices Based on Models and Other Valuation Methods (b)
   
14
   
(855
)
 
(713
)
 
173
   
381
   
464
   
(536
)
Total
 
$
590
 
$
385
 
$
512
 
$
490
 
$
381
 
$
464
 
$
2,822
 

(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” is in 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.
(c)
Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Beginning Balance December 31, 2004
 
$
657
 
Changes in Fair Value (a)
   
(4,094
)
Reclassifications from AOCI to Net Income (b)
   
(242
)
Ending Balance March 31, 2005
 
$
(3,679
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $3,634 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$40
 
$88
 
$43
 
$26
 
$157
 
$511
 
$220
 
$75
 

VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $127 million and $120 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
182,194
 
$
268,858
 
Sales to AEP Affiliates
   
4,964
   
18,130
 
TOTAL
   
187,158
   
286,988
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
6,075
   
23,106
 
Fuel from Affiliates for Electric Generation
   
23
   
40,199
 
Purchased Electricity for Resale
   
15,370
   
10,086
 
Purchased Electricity from AEP Affiliates
   
-
   
4,073
 
Other Operation
   
65,660
   
75,441
 
Maintenance
   
17,039
   
15,404
 
Depreciation and Amortization
   
29,286
   
29,097
 
Taxes Other Than Income Taxes
   
22,531
   
22,057
 
Income Taxes
   
1,461
   
12,006
 
TOTAL
   
157,445
   
231,469
 
               
OPERATING INCOME
   
29,713
   
55,519
 
               
Nonoperating Income
   
11,155
   
12,102
 
Nonoperating Expenses
   
15,137
   
5,108
 
Nonoperating Income Tax Credit
   
2,485
   
20
 
Interest Charges
   
27,079
   
33,129
 
               
NET INCOME
   
1,137
   
29,404
 
               
Preferred Stock Dividend Requirements
   
60
   
60
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
1,077
 
$
29,344
 

The common stock of TCC is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
55,292
 
$
132,606
 
$
1,083,023
 
$
(61,872
)
$
1,209,049
 
                                 
Common Stock Dividends
               
(24,000
)
       
(24,000
)
Preferred Stock Dividends
               
(60
)
       
(60
)
TOTAL
                           
1,184,989
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $7,411
                     
(13,763
)
 
(13,763
)
Minimum Pension Liability, Net of Tax  of $0
                     
(2,466
)
 
(2,466
)
NET INCOME
               
29,404
         
29,404
 
TOTAL COMPREHENSIVE INCOME
                           
13,175
 
                                 
MARCH 31, 2004
 
$
55,292
 
$
132,606
 
$
1,088,367
 
$
(78,101
)
$
1,198,164
 
                                 
DECEMBER 31, 2004
 
$
55,292
 
$
132,606
 
$
1,084,904
 
$
(4,159
)
$
1,268,643
 
                                 
Preferred Stock Dividends
               
(60
)
       
(60
)
TOTAL
                           
1,268,583
 
                                 
COMPREHENSIVE INCOME (LOSS)
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,335
                     
(4,336
)
 
(4,336
)
NET INCOME
               
1,137
         
1,137
 
TOTAL COMPREHENSIVE LOSS
                           
(3,199
)
                                 
MARCH 31, 2005
 
$
55,292
 
$
132,606
 
$
1,085,981
 
$
(8,495
)
$
1,265,384
 

See Notes to Financial Statements of Registrant Subsidiaries.


 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Transmission
 
$
791,529
 
$
788,371
 
Distribution
   
1,443,548
   
1,433,380
 
General
   
219,463
   
220,435
 
Construction Work in Progress
   
53,481
   
50,612
 
Total
   
2,508,021
   
2,492,798
 
Accumulated Depreciation and Amortization
   
729,655
   
725,225
 
TOTAL - NET
   
1,778,366
   
1,767,573
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
2,360
   
1,577
 
Bond Defeasance Funds
   
21,642
   
22,110
 
TOTAL
   
24,002
   
23,687
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
973
   
-
 
Other Cash Deposits
   
103,601
   
135,132
 
Accounts Receivable:
             
Customers
   
156,320
   
157,431
 
Affiliated Companies
   
12,168
   
67,860
 
Accrued Unbilled Revenues
   
23,327
   
21,589
 
Allowance for Uncollectible Accounts
   
(688
)
 
(3,493
)
Materials and Supplies
   
12,240
   
12,288
 
Risk Management Assets
   
7,067
   
14,048
 
Margin Deposits
   
2,778
   
1,891
 
Prepayments and Other Current Assets
   
15,464
   
9,151
 
TOTAL
   
333,250
   
415,897
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
18,562
   
15,236
 
Wholesale Capacity Auction True-Up
   
574,027
   
559,973
 
Unamortized Loss on Reacquired Debt
   
11,576
   
11,842
 
Designated for Securitization
   
1,345,935
   
1,361,299
 
Deferred Debt - Restructuring
   
11,368
   
11,596
 
Other
   
95,921
   
102,032
 
Securitized Transition Assets
   
632,000
   
642,384
 
Long-term Risk Management Assets
   
4,321
   
9,508
 
Prepaid Pension Obligations
   
109,995
   
109,628
 
Deferred Property Taxes
   
29,820
   
-
 
Deferred Charges
   
33,951
   
36,986
 
TOTAL
   
2,867,476
   
2,860,484
 
               
Assets Held for Sale - Texas Generation Plants
   
635,776
   
628,149
 
               
TOTAL ASSETS
 
$
5,638,870
 
$
5,695,790
 
 
See Notes to Financial Statements of Registrant Subsidiaries.


 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
Common Shareholder’s Equity:
             
Common Stock - $25 par value per share:
             
Authorized - 12,000,000 shares
             
Outstanding - 2,211,678 shares
 
$
55,292
 
$
55,292
 
Paid-in Capital
   
132,606
   
132,606
 
Retained Earnings
   
1,085,981
   
1,084,904
 
Accumulated Other Comprehensive Income (Loss)
   
(8,495
)
 
(4,159
)
Total Common Shareholder’s Equity
   
1,265,384
   
1,268,643
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
5,940
   
5,940
 
Total Shareholders’ Equity
   
1,271,324
   
1,274,583
 
Long-term Debt - Nonaffiliated
   
1,672,695
   
1,541,552
 
TOTAL
   
2,944,019
   
2,816,135
 
CURRENT LIABILITIES
             
Long-term Debt Due Within One Year - Nonaffiliated
   
116,997
   
365,742
 
Advances from Affiliates
   
238,693
   
207
 
Accounts Payable:
             
General
   
64,384
   
109,688
 
Affiliated Companies
   
68,003
   
64,045
 
Customer Deposits
   
4,974
   
6,147
 
Taxes Accrued
   
66,229
   
184,014
 
Interest Accrued
   
19,589
   
41,227
 
Risk Management Liabilities
   
10,663
   
8,394
 
Obligations Under Capital Leases
   
431
   
412
 
Other
   
17,511
   
20,115
 
TOTAL
   
607,474
   
799,991
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
1,253,495
   
1,247,111
 
Long-term Risk Management Liabilities
   
2,124
   
4,896
 
Regulatory Liabilities:
             
Asset Removal Costs
   
103,419
   
102,624
 
Deferred Investment Tax Credits
   
106,677
   
107,743
 
Over-recovery of Fuel Costs
   
214,426
   
211,526
 
Retail Clawback
   
61,384
   
61,384
 
Other
   
74,318
   
76,653
 
Obligations Under Capital Leases
   
498
   
468
 
Deferred Credits and Other
   
16,525
   
17,276
 
TOTAL
   
1,832,866
   
1,829,681
 
               
Liabilities Held for Sale - Texas Generation Plants
   
254,511
   
249,983
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
5,638,870
 
$
5,695,790
 

See Notes to Financial Statements of Registrant Subsidiaries.

 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
1,137
 
$
29,404
 
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
             
Depreciation and Amortization
   
29,286
   
29,097
 
Accretion Expense
   
4,529
   
4,067
 
Deferred Income Taxes
   
(5,045
)
 
(3,401
)
Deferred Investment Tax Credits
   
(1,066
)
 
(1,302
)
Deferred Property Taxes
   
(29,820
)
 
(33,660
)
Pension and Postemployment Benefit Reserves
   
(1,072
)
 
259
 
Mark-to-Market of Risk Management Contracts
   
6,879
   
5,035
 
Pension Contributions
   
(57
)
 
-
 
Carrying Costs
   
5,141
   
-
 
Wholesale Capacity Auction True-up
   
769
   
-
 
Over/Under Fuel Recovery
   
2,900
   
13,000
 
(Gain)/Loss on Sale of Assets
   
(48
)
 
(49
)
Change in Other Noncurrent Assets
   
(7,731
)
 
1,439
 
Change in Other Noncurrent Liabilities
   
6,929
   
(11,037
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
52,260
   
937
 
Fuel, Materials and Supplies
   
98
   
499
 
Accounts Payable
   
(41,346
)
 
(14,259
)
Taxes Accrued
   
(117,785
)
 
31,652
 
Customer Deposits
   
(1,173
)
 
1,974
 
Interest Accrued
   
(21,638
)
 
(19,948
)
Other Current Assets
   
(1,879
)
 
(2,527
)
Other Current Liabilities
   
(2,584
)
 
(5,307
)
Net Cash Flows From (Used For) Operating Activities
   
(121,316
)
 
25,873
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(27,534
)
 
(23,748
)
Change in Other Cash Deposits, Net
   
31,531
   
28,330
 
Net Cash Flows From Investing Activities
   
3,997
   
4,582
 
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt
   
159,252
   
-
 
Retirement of Long-term Debt
   
(279,386
)
 
(29,864
)
Changes in Advances to/from Affiliates, Net
   
238,486
   
24,742
 
Dividends Paid on Common Stock
   
-
   
(24,000
)
Dividends Paid on Cumulative Preferred Stock
   
(60
)
 
(60
)
Net Cash Flows From (Used For) Financing Activities
   
118,292
   
(29,182
)
               
Net Increase in Cash and Cash Equivalents
   
973
   
1,273
 
Cash and Cash Equivalents at Beginning of Period
   
-
   
760
 
Cash and Cash Equivalents at End of Period
 
$
973
 
$
2,033
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $44,721,000 and $49,928,000 and for income taxes was $132,960,000 and $(7,567,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $157,000 and $69,000 in 2005 and 2004, respectively.

See Notes to Respective Financial Statements.

 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to TCC’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to TCC.
 
   
Footnote
Reference
 
       
Significant Accounting Matters
 
 Note 1
 
New Accounting Pronouncements
 
 Note 2
 
Rate Matters
 
 Note 3
 
Customer Choice and Industry Restructuring
 
 Note 4
 
Commitments and Contingencies
 
 Note 5
 
Guarantees
 
 Note 6
 
Dispositions and Assets Held for Sale
 
 Note 7
 
Benefit Plans
 
 Note 8
 
Business Segments
 
 Note 9
 
Financing Activities
 
 Note 10
 
 
 

 
 
 
 
 
 
 
 
 
 
 

AEP TEXAS NORTH COMPANY


 
 
 
 
 
 
 
 
 
 
 
 
 
 




AEP TEXAS NORTH COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
13
 
               
Changes in Gross Margin:
             
Texas Supply
   
(3
)
     
Off-system Sales
   
(2
)
     
Other Revenues
   
(4
)
     
Total Change in Gross Margin
         
(9
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
2
       
Taxes Other Than Income Taxes
   
(1
)
     
Nonoperating Income and Expenses, Net
   
(2
)
     
Interest Charges
   
1
       
Total Change in Operating Expenses and Other
         
-
 
               
Income Tax Expense
         
3
 
               
First Quarter of 2005 Net Income
       
$
7
 

Net Income decreased $6 million to $7 million in the first quarter of 2005. The key drivers of the decrease were a $9 million decrease in gross margin offset by a $3 million decrease in Income Tax Expense.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Texas Supply margins decreased by $3 million primarily due to the loss of ERCOT reliability-must-run (RMR) revenue of $2 million.
·
Margins from Off-system Sales for 2005 decreased by $2 million in comparison to 2004 primarily due to lower optimization activity.
·
Other Revenues margins decreased $4 million primarily due to a prior year unfavorable adjustment for affiliated OATT and ancillary services resulting from revised ERCOT data received for the years 2001 through 2003.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $2 million primarily due to decreased production plant operations and related maintenance for RMR plants no longer in use offset in part by increased transmission cost related to ERCOT.
·
Taxes Other Than Income Taxes increased $1 million primarily due to property related taxes offset in part by lower state and local franchise tax expense.
·
Nonoperating Income and Expenses, Net decreased $2 million primarily due to the absence of risk management activities in the first quarter of 2005.
·
Interest Charges decreased $1 million primarily due to long-term debt maturities in 2004 and interest in 2004 related to the FERC settlement with wholesale customers.

Income Taxes

The effective tax rate for the first quarter of 2005 and 2004 was 33.8% and 34.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits and state income taxes. The effective tax rate remained relatively flat for the comparative period.

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-
 

Financing Activity

There were no long-term debt issuances or retirements during the first three months of 2005.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effects on us.

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.
 
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
4,192
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(1,345
)
Fair Value of New Contracts When Entered During the Period (b)
   
14
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
(1,642
)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
-
 
Total MTM Risk Management Contract Net Assets
   
1,219
 
Net Cash Flow Hedge Contracts (f)
   
1,006
 
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
2,225
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
 

Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Cash Flow Hedges
 
Total (b)
 
Current Assets
 
$
2,140
 
$
2,390
 
$
4,530
 
Noncurrent Assets
   
1,848
   
20
   
1,868
 
Total MTM Derivative Contract Assets
   
3,988
   
2,410
   
6,398
 
                     
Current Liabilities
   
(1,900
)
 
(1,355
)
 
(3,255
)
Noncurrent Liabilities
   
(869
)
 
(49
)
 
(918
)
Total MTM Derivative Contract Liabilities
   
(2,769
)
 
(1,404
)
 
(4,173
)
                     
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
1,219
 
$
1,006
 
$
2,225
 

(a)
Does not include Cash Flow Hedges.
(b)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009
 
Total (c)
 
Prices Actively Quoted - Exchange Traded Contracts
 
 
$
(263
)
$
101
 
$
210
 
$
-
 
$
-
 
$
-
 
$
48
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
512
   
435
   
320
   
137
   
-
   
-
   
1,404
 
Prices Based on Models and Other Valuation Methods (b)
   
4
   
(370
)
 
(308
)
 
75
   
165
   
201
   
(233
)
Total
 
$
253
 
$
166
 
$
222
 
$
212
 
$
165
 
$
201
 
$
1,219
 

(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” is in 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.
(c)
Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Beginning Balance December 31, 2004
 
$
285
 
Changes in Fair Value (a)
   
(670
)
Reclassifications from AOCI to Net Income (b)
   
(104
)
Ending Balance March 31, 2005
 
$
(489
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $470 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$17
 
$38
 
$19
 
$11
 
$68
 
$221
 
$95
 
$33
 

VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $15 million and $13 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or financial position.



AEP TEXAS NORTH COMPANY
STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
71,943
 
$
88,712
 
Sales to AEP Affiliates
   
11,290
   
14,718
 
TOTAL
   
83,233
   
103,430
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
12,611
   
7,500
 
Fuel from Affiliates for Electric Generation
   
372
   
11,224
 
Purchased Electricity for Resale
   
16,338
   
18,023
 
Purchased Electricity from AEP Affiliates
   
22
   
3,532
 
Other Operation
   
18,561
   
20,381
 
Maintenance
   
4,219
   
4,683
 
Depreciation and Amortization
   
10,155
   
9,692
 
Taxes Other Than Income Taxes
   
5,705
   
5,104
 
Income Taxes
   
3,586
   
5,941
 
TOTAL
   
71,569
   
86,080
 
               
OPERATING INCOME
   
11,664
   
17,350
 
               
Nonoperating Income
   
36,002
   
13,756
 
Nonoperating Expenses
   
35,108
   
10,936
 
Nonoperating Income Tax Expense
   
180
   
894
 
Interest Charges
   
4,984
   
6,180
 
               
NET INCOME
   
7,394
   
13,096
 
               
Preferred Stock Dividend Requirements
   
26
   
26
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
7,368
 
$
13,070
 

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.




AEP TEXAS NORTH COMPANY
STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
137,214
 
$
2,351
 
$
125,428
 
$
(26,718
)
$
238,275
 
                                 
Common Stock Dividends
               
(2,000
)
       
(2,000
)
Preferred Stock Dividends
               
(26
)
       
(26
)
TOTAL
                           
236,249
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,482
                     
(4,610
)
 
(4,610
)
NET INCOME
               
13,096
         
13,096
 
TOTAL COMPREHENSIVE INCOME
                           
8,486
 
                                 
MARCH 31, 2004
 
$
137,214
 
$
2,351
 
$
136,498
 
$
(31,328
)
$
244,735
 
                                 
DECEMBER 31, 2004
 
$
137,214
 
$
2,351
 
$
170,984
 
$
(128
)
$
310,421
 
                                 
Common Stock Dividends
               
(9,427
)
       
(9,427
)
Preferred Stock Dividends
               
(26
)
       
(26
)
TOTAL
                           
300,968
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $416
                     
(774
)
 
(774
)
NET INCOME
               
7,394
         
7,394
 
TOTAL COMPREHENSIVE INCOME
                           
6,620
 
                                 
MARCH 31, 2005
 
$
137,214
 
$
2,351
 
$
168,925
 
$
(902
)
$
307,588
 

See Notes to Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY
BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
288,107
 
$
287,212
 
Transmission
   
280,447
   
281,359
 
Distribution
   
479,251
   
474,961
 
General
   
115,774
   
115,174
 
Construction Work in Progress
   
21,487
   
23,621
 
Total
   
1,185,066
   
1,182,327
 
Accumulated Depreciation and Amortization
   
407,278
   
405,933
 
TOTAL - NET
   
777,788
   
776,394
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
1,167
   
1,407
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
304
   
-
 
Other Cash Deposits
   
2,308
   
2,308
 
Advances to Affiliates
   
52,736
   
51,504
 
Accounts Receivable:
             
Customers
   
53,018
   
90,109
 
Affiliated Companies
   
25,696
   
21,474
 
Accrued Unbilled Revenues
   
2,567
   
3,789
 
Allowance for Uncollectible Accounts
   
(30
)
 
(787
)
Unbilled Construction Costs
   
16,127
   
22,065
 
Fuel Inventory
   
5,736
   
3,148
 
Materials and Supplies
   
8,389
   
8,273
 
Risk Management Assets
   
4,530
   
6,071
 
Margin Deposits
   
2,676
   
818
 
Prepayments and Other
   
1,256
   
1,053
 
TOTAL
   
175,313
   
209,825
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
Deferred Debt - Restructuring
   
5,971
   
6,093
 
Unamortized Loss on Reacquired Debt
   
1,805
   
2,147
 
Other
   
3,675
   
3,783
 
Long-term Risk Management Assets
   
1,868
   
4,110
 
Prepaid Pension Obligations
   
44,917
   
44,911
 
Deferred Property Taxes
   
12,218
   
-
 
Other Deferred Charges
   
2,629
   
2,859
 
TOTAL
   
73,083
   
63,903
 
               
TOTAL ASSETS
 
$
1,027,351
 
$
1,051,529
 

See Notes to Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
Common Shareholder’s Equity:
             
Common Stock - $25 par value per share:
             
 Authorized - 7,800,000 shares
             
 Outstanding - 5,488,560 shares
 
$
137,214
 
$
137,214
 
Paid-in Capital
   
2,351
   
2,351
 
Retained Earnings
   
168,925
   
170,984
 
Accumulated Other Comprehensive Income (Loss)
   
(902
)
 
(128
)
Total Common Shareholder’s Equity
   
307,588
   
310,421
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
2,357
   
2,357
 
Total Shareholders’ Equity
   
309,945
   
312,778
 
Long-term Debt - Nonaffiliated
   
276,773
   
276,748
 
TOTAL
   
586,718
   
589,526
 
CURRENT LIABILITIES
             
Long-term Debt Due Within One Year - Nonaffiliated
   
37,609
   
37,609
 
Accounts Payable:
             
General
   
14,955
   
22,444
 
Affiliated Companies
   
53,078
   
52,801
 
Customer Deposits
   
594
   
1,020
 
Taxes Accrued
   
26,357
   
37,269
 
Interest Accrued
   
3,372
   
5,044
 
Risk Management Liabilities
   
3,255
   
3,628
 
Obligations Under Capital Leases
   
227
   
220
 
Other
   
7,344
   
9,628
 
TOTAL
   
146,791
   
169,663
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
139,898
   
138,465
 
Long-term Risk Management Liabilities
   
918
   
2,116
 
Regulatory Liabilities:
             
Asset Removal Costs
   
81,991
   
81,143
 
Deferred Investment Tax Credits
   
18,380
   
18,698
 
Over-recovery of Fuel Costs
   
5,320
   
3,920
 
Retail Clawback
   
13,924
   
13,924
 
Excess Earnings
   
13,146
   
13,270
 
SFAS 109 Regulatory Liability, Net
   
7,824
   
8,500
 
Other
   
1,156
   
1,319
 
Obligations Under Capital Leases
   
383
   
314
 
Deferred Credits and Other
   
10,902
   
10,671
 
TOTAL
   
293,842
   
292,340
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
1,027,351
 
$
1,051,529
 

See Notes to Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
7,394
 
$
13,096
 
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
             
Depreciation and Amortization
   
10,155
   
9,692
 
Deferred Income Taxes
   
(1,221
)
 
(1
)
Deferred Investment Tax Credits
   
(318
)
 
(339
)
Deferred Property Taxes
   
(12,218
)
 
(11,100
)
Mark-to-Market of Risk Management Contracts
   
2,973
   
2,096
 
Over/Under Fuel Recovery
   
1,400
   
1,500
 
Change in Other Noncurrent Assets
   
(1,705
)
 
(802
)
Change in Other Noncurrent Liabilities
   
1,872
   
1,204
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
33,334
   
6,754
 
Fuel, Materials and Supplies
   
(2,704
)
 
2,439
 
Accounts Payable
   
(7,212
)
 
(11,227
)
Taxes Accrued
   
(10,912
)
 
8,535
 
Customer Deposits
   
(426
)
 
305
 
Interest Accrued
   
(1,672
)
 
(1,962
)
Other Current Assets
   
4,361
   
(5,478
)
Other Current Liabilities
   
(2,270
)
 
(2,309
)
Net Cash Flows From Operating Activities
   
20,831
   
12,403
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(10,092
)
 
(7,971
)
Change in Other Cash Deposits, Net
   
-
   
581
 
Proceeds from Sale of Assets
   
250
   
-
 
Net Cash Flows Used For Investing Activities
   
(9,842
)
 
(7,390
)
               
FINANCING ACTIVITIES
             
Retirement of Long-term Debt
   
-
   
(24,036
)
Changes in Advances to/from Affiliates, Net
   
(1,232
)
 
21,603
 
Dividends Paid on Common Stock
   
(9,427
)
 
(2,000
)
Dividends Paid on Cumulative Preferred Stock
   
(26
)
 
(26
)
Net Cash Flows Used For Financing Activities
   
(10,685
)
 
(4,459
)
               
Net Increase in Cash and Cash Equivalents
   
304
   
554
 
Cash and Cash Equivalents at Beginning of Period
   
-
   
-
 
Cash and Cash Equivalents at End of Period
 
$
304
 
$
554
 

SUPPLEMENTAL DISCLOSURE:
     
Cash paid (received) for interest net of capitalized amounts was $6,236,000 and $7,568,000 and for income taxes was $17,447,000 and $(412,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 and 2004 were $137,000 and $25,000, respectively.

See Notes to Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to TNC’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to TNC.

 
   
Footnote
Reference
 
       
Significant Accounting Matters
 
 Note 1
 
New Accounting Pronouncements
 
 Note 2
 
Rate Matters
 
 Note 3
 
Customer Choice and Industry Restructuring
 
 Note 4
 
Commitments and Contingencies
 
 Note 5
 
Guarantees
 
 Note 6
 
Benefit Plans
 
 Note 8
 
Business Segments
 
 Note 9
 
Financing Activities
 
 Note 10
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
 

APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
 
 
 
 
 
 
 
 
 
 
 





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
 
Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
65
 
               
Changes in Gross Margin:
             
Retail Margins
   
(32
)
     
Off-system Sales
   
15
       
Transmission Revenues
   
(8
)
     
Other Revenues
   
4
       
Total Change in Gross Margin
         
(21
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(8
)
     
Depreciation and Amortization
   
(2
)
     
Taxes Other Than Income Taxes
   
(1
)
     
Nonoperating Income and Expenses, Net
   
(3
)
     
Interest Charges
   
1
       
Total Change in Operating Expenses and Other
         
(13
)
               
Income Tax Expense
         
16
 
               
First Quarter of 2005 Net Income
       
$
47
 

Net Income decreased $18 million to $47 million in the first quarter of 2005. The key drivers of the decrease were a $21 million decrease in gross margin and a $13 million net increase in operating expenses and other partially offset by a $16 million decrease in income taxes.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins decreased by $32 million in comparison to 2004 primarily due to our higher MLR share caused by the increase in our peak that was established in December 2004 resulting in a $16 million increase in capacity settlement payments under the Interconnection Agreement. In addition, there was a $16 million increase in under-recovered fuel.
·
Margins from Off-system Sales for 2005 increased by $15 million in comparison to 2004 primarily due to higher sales volumes primarily caused by our new peak established in December 2004 as well as higher optimization activity.
·
Margins from Transmission Revenues decreased $8 million primarily due to the elimination of $12 million of revenues related to through and out rates partially offset by an increase of $4 million in unbundled transmission revenues due to the addition of SECA rates as mandated by the FERC.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $8 million primarily due to increases in plant maintenance, removal costs and PJM scheduling fees partially offset by the settlement and cancellation of the corporate owned life insurance policy in February 2005.
·
Nonoperating Income and Expenses, Net decreased $3 million primarily due to unfavorable results from risk management activities.

Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were 34.3% and 38.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences including COLI and lower state income taxes.

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+
 

Cash Flow

Cash flows for the three months ended March 31, 2005 and 2004 were as follows:

   
2005
 
2004
 
   
(in thousands)
 
Cash and cash equivalents at beginning of period
 
$
536
 
$
4,561
 
Cash flows from (used for):
             
Operating activities
   
94,570
   
180,602
 
Investing activities
   
(151,768
)
 
(49,024
)
Financing activities
   
57,875
   
(131,630
)
Net increase (decrease) in cash and cash equivalents
   
677
   
(52
)
Cash and cash equivalents at end of period
 
$
1,213
 
$
4,509
 

Operating Activities

Our net cash flows from operating activities were $95 million in 2005. We produced income of $47 million during the period and noncash expense items of $50 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had no significant items.

Our net cash flows from operating activities were $181 million in 2004. We produced income of $65 million during the period and had a noncash expense item of $48 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital had one significant item; a decrease in Accounts Receivable of $55 million due to settlements of affiliated receivables at December 2003 as well as a lower MLR share of physical off-system sales from December 2003 to March 2004.

Investing Activities

Cash flows used for investing activities during 2005 and 2004 primarily reflect our construction expenditures of $139 million and $90 million, respectively. Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades. In 2005 and 2004, capital projects for transmission expenditures are primarily related to the Jacksons Ferry-Wyoming 765 kV line. Environmental upgrades include the installation of selective catalytic reduction (SCR) equipment on Amos Unit 1 and the flue gas desulfurization project at the Mountaineer Plant. For the remainder of 2005, we expect our Construction Expenditures to be approximately $559 million.

Financing Activities

In 2005, we issued Senior Unsecured Notes of $200 million with an interest rate of 4.95% and received a capital contribution from our parent of $100 million. In addition, we repaid $211 million of advances from affiliates and advanced $29 million to our affiliates.

In 2004, we retired $40 million of Installment Purchase Contracts with an interest rate of 5.45%. In addition, we repaid $66 million of advances from affiliates and paid $25 million in common stock dividends.

Financing Activity

Long-term debt issuances and retirements during the first three months of 2005 were:

Issuances

   
Principal
 
Interest
 
Due
 
Type of Debt
 
Amount
 
Rate
 
Date
 
   
(in thousands)
 
(%)
     
Senior Unsecured Notes
 
$
200,000
   
4.95
   
2015
 
Retirements

None

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
54,124
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(9,032
)
Fair Value of New Contracts When Entered During the Period (b)
   
305
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
15,325
 
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
4,596
 
Total MTM Risk Management Contract Net Assets
   
65,318
 
Net Cash Flow and Fair Value Hedge Contracts (f)
   
(17,544
)
DETM Assignment (g)
   
(21,570
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
26,204
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
 
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Hedges
 
DETM
Assignment (b)
 
Total (c)
 
Current Assets
 
$
120,952
 
$
5,972
 
$
-
 
$
126,924
 
Noncurrent Assets
   
144,582
   
719
   
-
   
145,301
 
Total MTM Derivative Contract Assets
   
265,534
   
6,691
   
-
   
272,225
 
                           
Current Liabilities
   
(111,460
)
 
(21,412
)
 
(8,829
)
 
(141,701
)
Noncurrent Liabilities
   
(88,756
)
 
(2,823
)
 
(12,741
)
 
(104,320
)
Total MTM Derivative Contract Liabilities
   
(200,216
)
 
(24,235
)
 
(21,570
)
 
(246,021
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
65,318
 
$
(17,544
)
$
(21,570
)
$
26,204
 

(a)
Does not include Cash Flow and Fair Value Hedges.
(b)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009 (c)
 
Total (d)
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
(9,621
)
$
3,704
 
$
7,671
 
$
-
 
$
-
 
$
-
 
$
1,754
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
18,437
   
19,928
   
13,827
   
6,359
   
-
   
-
   
58,551
 
Prices Based on Models and Other Valuation Methods (b)
   
(351
)
 
(10,244
)
 
(7,397
)
 
5,262
   
9,398
   
8,345
   
5,013
 
Total
 
$
8,465
 
$
13,388
 
$
14,101
 
$
11,621
 
$
9,398
 
$
8,345
 
$
65,318
 

(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” is in 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.
(c)
There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $8 million of this mark-to-market value is in 2010.
(d)
Amounts exclude Cash Flow and Fair Value Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate risk to existing floating rate debt, to manage interest rate exposure on anticipated floating rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Foreign
Currency
 
Interest Rate
 
Total
 
Beginning Balance December 31, 2004
 
$
2,422
 
$
(176
)
$
(11,570
)
$
(9,324
)
Changes in Fair Value (a)
   
(7,165
)
 
-
   
2,996
   
(4,169
)
Reclassifications from AOCI to Net Income (b)
   
(3,817
)
 
2
   
274
   
(3,541
)
Ending Balance March 31, 2005
 
$
(8,560
)
$
(174
)
$
(8,300
)
$
(17,034
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is an $8,899 thousand loss.
 
Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$629
 
$1,391
 
$682
 
$411
 
$577
 
$1,883
 
$812
 
$277
 
 
VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $114 million and $99 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
504,141
 
$
473,225
 
Sales to AEP Affiliates
   
52,938
   
53,882
 
TOTAL
   
557,079
   
527,107
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
113,381
   
110,711
 
Purchased Electricity for Resale
   
28,233
   
16,644
 
Purchased Electricity from AEP Affiliates
   
126,963
   
90,487
 
Other Operation
   
71,008
   
68,742
 
Maintenance
   
47,190
   
41,320
 
Depreciation and Amortization
   
49,959
   
47,913
 
Taxes Other Than Income Taxes
   
24,039
   
23,453
 
Income Taxes
   
26,242
   
40,440
 
TOTAL
   
487,015
   
439,710
 
               
OPERATING INCOME
   
70,064
   
87,397
 
               
Nonoperating Income
   
3,487
   
5,547
 
Nonoperating Expenses
   
4,563
   
2,533
 
Nonoperating Income Tax Credit
   
1,883
   
362
 
Interest Charges
   
24,199
   
25,437
 
               
NET INCOME
   
46,672
   
65,336
 
               
Preferred Stock Dividend Requirements, Including Capital Stock Expense
   
797
   
823
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
45,875
 
$
64,513
 

The common stock of APCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
260,458
 
$
719,899
 
$
408,718
 
$
(52,088
)
$
1,336,987
 
                                 
Common Stock Dividends
               
(25,000
)
       
(25,000
)
Preferred Stock Dividends
               
(200
)
       
(200
)
Capital Stock Expense
         
623
   
(623
)
       
-
 
TOTAL
                           
1,311,787
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,642
                     
(3,050
)
 
(3,050
)
NET INCOME
               
65,336
         
65,336
 
TOTAL COMPREHENSIVE INCOME
                           
62,286
 
                                 
MARCH 31, 2004
 
$
260,458
 
$
720,522
 
$
448,231
 
$
(55,138
)
$
1,374,073
 
                                 
DECEMBER 31, 2004
 
$
260,458
 
$
722,314
 
$
508,618
 
$
(81,672
)
$
1,409,718
 
                                 
Capital Contribution from Parent
         
100,000
               
100,000
 
Preferred Stock Dividends
               
(200
)
       
(200
)
Capital Stock Expense
         
597
   
(597
)
       
-
 
TOTAL
                           
1,509,518
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $4,151
                     
(7,710
)
 
(7,710
)
NET INCOME
               
46,672
         
46,672
 
TOTAL COMPREHENSIVE INCOME
                           
38,962
 
                                 
MARCH 31, 2005
 
$
260,458
 
$
822,911
 
$
554,493
 
$
(89,382
)
$
1,548,480
 

See Notes to Financial Statements of Registrant Subsidiaries.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
2,525,139
 
$
2,502,273
 
Transmission
   
1,257,336
   
1,255,390
 
Distribution
   
2,088,544
   
2,070,377
 
General
   
294,211
   
302,474
 
Construction Work in Progress
   
473,066
   
399,116
 
Total
   
6,638,296
   
6,529,630
 
Accumulated Depreciation and Amortization
   
2,458,894
   
2,443,218
 
TOTAL - NET
   
4,179,402
   
4,086,412
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
20,834
   
20,378
 
Other Investments
   
13,029
   
18,775
 
TOTAL
   
33,863
   
39,153
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
1,213
   
536
 
Other Cash Deposits
   
14,995
   
1,133
 
Advance to Affiliates
   
29,054
   
-
 
Accounts Receivable:
             
Customers
   
151,080
   
126,422
 
Affiliated Companies
   
126,573
   
140,950
 
Accrued Unbilled Revenues
   
34,147
   
51,427
 
Miscellaneous
   
1,311
   
1,264
 
Allowance for Uncollectible Accounts
   
(1,722
)
 
(5,561
)
Risk Management Assets
   
126,924
   
81,811
 
Fuel
   
52,058
   
45,756
 
Materials and Supplies
   
45,106
   
45,644
 
Margin Deposits
   
15,800
   
8,329
 
Prepayments and Other
   
17,280
   
12,192
 
TOTAL
   
613,819
   
509,903
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
343,652
   
343,415
 
Transition Regulatory Assets
   
24,406
   
25,467
 
Unamortized Loss on Reacquired Debt
   
17,356
   
18,157
 
Other
   
52,448
   
36,368
 
Long-term Risk Management Assets
   
145,301
   
81,245
 
Emission Allowances
   
43,530
   
38,931
 
Deferred Property Taxes
   
40,423
   
37,071
 
Deferred Charges and Other
   
10,880
   
23,796
 
TOTAL
   
677,996
   
604,450
 
               
TOTAL ASSETS
 
$
5,505,080
 
$
5,239,918
 

See Notes to Financial Statements of Registrant Subsidiaries.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
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
   
822,911
   
722,314
 
 Retained Earnings
   
554,493
   
508,618
 
 Accumulated Other Comprehensive Income (Loss)
   
(89,382
)
 
(81,672
)
Total Common Shareholder’s Equity
   
1,548,480
   
1,409,718
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
17,784
   
17,784
 
Total Shareholders’ Equity
   
1,566,264
   
1,427,502
 
Long-term Debt - Nonaffiliated
   
1,352,724
   
1,254,588
 
TOTAL
   
2,918,988
   
2,682,090
 
               
CURRENT LIABILITIES
             
Long-term Debt Due Within One Year - Nonaffiliated
   
630,010
   
530,010
 
Advances from Affiliates
   
-
   
211,060
 
Accounts Payable:
             
General
   
176,933
   
130,710
 
Affiliated Companies
   
71,712
   
76,314
 
Risk Management Liabilities
   
141,701
   
89,136
 
Taxes Accrued
   
69,088
   
90,404
 
Interest Accrued
   
38,041
   
21,076
 
Customer Deposits
   
56,379
   
42,822
 
Obligations Under Capital Leases
   
6,577
   
6,742
 
Other
   
50,191
   
56,645
 
TOTAL
   
1,240,632
   
1,254,919
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
858,067
   
852,536
 
Regulatory Liabilities:
             
Asset Removal Costs
   
92,337
   
95,763
 
Over-recovery of Fuel Cost
   
61,163
   
57,843
 
Deferred Investment Tax Credits
   
29,248
   
30,382
 
Unrealized Gain on Forward Commitments
   
35,685
   
23,270
 
Employee Benefits and Pension Obligations
   
110,725
   
130,530
 
Long-term Risk Management Liabilities
   
104,320
   
57,349
 
Asset Retirement Obligations
   
25,101
   
24,626
 
Obligations Under Capital Leases
   
12,000
   
13,136
 
Deferred Credits
   
16,814
   
17,474
 
TOTAL
   
1,345,460
   
1,302,909
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
5,505,080
 
$
5,239,918
 

See Notes to Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
             
Net Income
 
$
46,672
 
$
65,336
 
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
             
Depreciation and Amortization
   
49,959
   
47,913
 
Accretion Expense
   
474
   
425
 
Deferred Income Taxes
   
9,445
   
14,742
 
Deferred Investment Tax Credits
   
(1,134
)
 
(1,089
)
Deferred Property Taxes
   
(3,352
)
 
(3,097
)
Pension Contributions
   
(19,937
)
 
-
 
Pension and Postemployment Benefit Reserves
   
96
   
(883
)
Mark-to-Market of Risk Management Contracts
   
(13,360
)
 
(8,015
)
Over/Under Fuel Recovery
   
3,320
   
2,499
 
Change in Other Noncurrent Assets
   
(9,809
)
 
(14,803
)
Change in Other Noncurrent Liabilities
   
(1,442
)
 
9,969
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
3,113
   
55,191
 
Fuel, Materials and Supplies
   
(5,764
)
 
(14,507
)
Accounts Payable
   
41,621
   
(25,777
)
Taxes Accrued
   
(21,316
)
 
26,910
 
Customer Deposits
   
13,557
   
10,984
 
Interest Accrued
   
16,965
   
17,869
 
Other Current Assets
   
(7,918
)
 
3,748
 
Other Current Liabilities
   
(6,620
)
 
(6,813
)
Net Cash Flows From Operating Activities
   
94,570
   
180,602
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(138,612
)
 
(89,583
)
Change in Other Cash Deposits, Net
   
(13,862
)
 
40,559
 
Proceeds from Sale of Assets
   
706
   
-
 
Net Cash Flows Used For Investing Activities
   
(151,768
)
 
(49,024
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt
   
198,189
   
-
 
Retirement of Long-term Debt
   
-
   
(40,002
)
Capital Contribution from Parent
   
100,000
   
-
 
Changes in Advances to/from Affiliates, Net
   
(240,114
)
 
(66,428
)
Dividends Paid on Common Stock
   
-
   
(25,000
)
Dividends Paid on Cumulative Preferred Stock
   
(200
)
 
(200
)
Net Cash Flows From (Used For) Financing Activities
   
57,875
   
(131,630
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
677
   
(52
)
Cash and Cash Equivalents at Beginning of Period
   
536
   
4,561
 
Cash and Cash Equivalents at End of Period
 
$
1,213
 
$
4,509
 

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $5,842,000 and $5,214,000 and for income taxes was $38,845,000 and $1,599,000 in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 and 2004 were $460,000 and $360,000, respectively.

See Notes to Respective Financial Statements.
 


 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to APCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to APCo.

   
Footnote
Reference
 
       
Significant Accounting Matters
 
 Note 1
 
New Accounting Pronouncements
 
 Note 2
 
Rate Matters
 
 Note 3
 
Commitments and Contingencies
 
 Note 5
 
Guarantees
 
 Note 6
 
Benefit Plans
 
 Note 8
 
Business Segments
 
 Note 9
 
Financing Activities
 
 Note 10
 
 
 
 

 

 
 
 
 
 
 
 
 
 
 
 

 
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 






COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
 
Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
45
 
               
Changes in Gross Margin:
             
Retail Margins
   
(5
)
     
Transmission Revenues
   
(6
)
     
Off-system Sales
   
1
       
Other Revenues
   
(2
)
     
Total Change in Gross Margin
         
(12
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
10
       
Depreciation and Amortization
   
(1
)
     
Taxes Other Than Income Taxes
   
(1
)
     
Nonoperating Income and Expenses, Net
   
3
       
Total Change in Operating Expenses and Other
         
11
 
               
Income Tax Expense
         
3
 
               
First Quarter of 2005 Net Income
       
$
47
 

Net Income remained relatively flat in the first quarter of 2005.

The major components of our decrease in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins were $5 million less than the prior period primarily due to lower usage by residential and industrial customers.
·
Margins from Transmission Revenues decreased $6 million primarily due to the loss of through and out rates as mandated by the FERC. The decrease was partially offset by an increase in unbundled transmission revenues due to the addition of SECA rates.

Operating Expenses and Other decreased between years as follows:

·
Other Operation and Maintenance expenses decreased $10 million primarily due to lower expenditures than estimated for storm expenses from the major ice storm in December 2004, the settlement and cancellation of the corporate owned life insurance policy in February 2005 and the establishment of a regulatory asset for PJM administrative fees.
·
Nonoperating Income and Expenses, Net increased $3 million primarily due to an establishment of a regulatory asset for carrying costs on environmental capital expenditures offset by lower margins on risk management activities.

Income Tax

The effective tax rates for the first quarter of 2005 and 2004 were 31.9% and 36.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to a decrease in state and local income taxes and changes in permanent differences including COLI.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

   
Moody’s
 
S&P
 
Fitch
 
               
Senior Unsecured Debt
   
A3
   
BBB
   
A-
 

Financing Activity

There were no long-term debt issuances or retirements during the first three months of 2005.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.
 
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
30,919
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(6,292
)
Fair Value of New Contracts When Entered During the Period (b)
   
268
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
8,528
 
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
-
 
Total MTM Risk Management Contract Net Assets
   
33,423
 
Net Cash Flow Hedge Contracts (f)
   
(6,739
)
DETM Assignment (g)
   
(11,038
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
15,646
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
 

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Cash Flow Hedges
 
DETM Assignment (b)
 
Total (c)
 
Current Assets
 
$
61,895
 
$
2,935
 
$
-
 
$
64,830
 
Noncurrent Assets
   
73,988
   
368
   
-
   
74,356
 
Total MTM Derivative Contract Assets
   
135,883
   
3,303
   
-
   
139,186
 
                           
Current Liabilities
   
(57,040
)
 
(9,114
)
 
(4,518
)
 
(70,672
)
Noncurrent Liabilities
   
(45,420
)
 
(928
)
 
(6,520
)
 
(52,868
)
Total MTM Derivative Contract Liabilities
   
(102,460
)
 
(10,042
)
 
(11,038
)
 
(123,540
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
33,423
 
$
(6,739
)
$
(11,038
)
$
15,646
 

(a)
Does not include Cash Flow Hedges.
(b)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009 (c)
 
Total (d)
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
(4,923
)
$
1,895
 
$
3,925
 
$
-
 
$
-
 
$
-
 
$
897
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
9,435
   
10,197
   
7,076
   
3,254
   
-
   
-
   
29,962
 
Prices Based on Models and Other Valuation Methods (b)
   
(181
)
 
(5,242
)
 
(3,785
)
 
2,692
   
4,810
   
4,270
   
2,564
 
Total
 
$
4,331
 
$
6,850
 
$
7,216
 
$
5,946
 
$
4,810
 
$
4,270
 
$
33,423
 

(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” is in 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.
(c)
There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $4.1 million of this mark-to-market value is in 2010.
(d)
Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Beginning Balance December 31, 2004
 
$
1,393
 
Changes in Fair Value (a)
   
(3,821
)
Reclassifications from AOCI to Net Income (b)
   
(1,953
)
Ending Balance March 31, 2005
 
$
(4,381
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $4,017 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Energy and Gas Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$322
 
$712
 
$349
 
$210
 
$332
 
$1,083
 
$467
 
$160
 
 
VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $55 million and $48 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
340,156
 
$
344,078
 
Sales to AEP Affiliates
   
24,093
   
18,619
 
TOTAL
   
364,249
   
362,697
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
61,352
   
41,637
 
Fuel From Affiliates for Electric Generation
   
-
   
8,848
 
Purchased Electricity for Resale
   
9,203
   
4,681
 
Purchased Electricity from AEP Affiliates
   
79,775
   
81,715
 
Other Operation
   
48,768
   
57,873
 
Maintenance
   
15,384
   
16,826
 
Depreciation and Amortization
   
38,198
   
36,818
 
Taxes Other Than Income Taxes
   
36,162
   
35,326
 
Income Taxes
   
20,422
   
24,465
 
TOTAL
   
309,264
   
308,189
 
               
OPERATING INCOME
   
54,985
   
54,508
 
               
Nonoperating Income
   
7,968
   
5,078
 
Nonoperating Expenses
   
756
   
734
 
Nonoperating Income Tax Expense
   
1,817
   
919
 
Interest Charges
   
12,912
   
12,814
 
               
NET INCOME
   
47,468
   
45,119
 
               
Preferred Stock Dividend Requirements including Capital Stock Expense
   
254
   
254
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
47,214
 
$
44,865
 

The common stock of CSPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
41,026
 
$
576,400
 
$
326,782
 
$
(46,327
)
$
897,881
 
                                 
Common Stock Dividends
               
(31,250
)
       
(31,250
)
Capital Stock Expense
         
254
   
(254
)
       
-
 
TOTAL
                           
866,631
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,028
                     
(1,910
)
 
(1,910
)
NET INCOME
               
45,119
         
45,119
 
TOTAL COMPREHENSIVE INCOME
                           
43,209
 
                                 
MARCH 31, 2004
 
$
41,026
 
$
576,654
 
$
340,397
 
$
(48,237
)
$
909,840
 
                                 
DECEMBER 31, 2004
 
$
41,026
 
$
577,415
 
$
341,025
 
$
(60,816
)
$
898,650
 
                                 
Common Stock Dividends
               
(28,500
)
       
(28,500
)
Capital Stock Expense
         
254
   
(254
)
       
-
 
TOTAL
                           
870,150
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $3,109
                     
(5,774
)
 
(5,774
)
NET INCOME
               
47,468
         
47,468
 
TOTAL COMPREHENSIVE INCOME
                           
41,694
 
                                 
MARCH 31, 2005
 
$
41,026
 
$
577,669
 
$
359,739
 
$
(66,590
)
$
911,844
 

See Notes to Financial Statements of Registrant Subsidiaries.




COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
1,664,673
 
$
1,658,552
 
Transmission
   
439,747
   
432,714
 
Distribution
   
1,316,498
   
1,300,252
 
General
   
164,314
   
167,985
 
Construction Work in Progress
   
127,079
   
131,743
 
Total
   
3,712,311
   
3,691,246
 
Accumulated Depreciation and Amortization
   
1,487,677
   
1,471,950
 
TOTAL - NET
   
2,224,634
   
2,219,296
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
21,648
   
22,322
 
Other Investments
   
4,115
   
5,147
 
TOTAL
   
25,763
   
27,469
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
671
   
25
 
Other Cash Deposits
   
7,158
   
33
 
Advances to Affiliates
   
59,416
   
141,550
 
Accounts Receivable:
             
Customers
   
46,277
   
41,130
 
Affiliated Companies
   
58,598
   
72,854
 
Accrued Unbilled Revenues
   
14,510
   
19,580
 
Miscellaneous
   
667
   
1,145
 
Allowance for Uncollectible Accounts
   
(76
)
 
(674
)
Fuel
   
27,255
   
34,026
 
Materials and Supplies
   
36,379
   
37,137
 
Risk Management Assets
   
64,830
   
46,631
 
Margin Deposits
   
8,229
   
4,848
 
Prepayments and Other
   
14,883
   
11,499
 
TOTAL
   
338,797
   
409,784
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
16,991
   
16,481
 
Transition Regulatory Assets
   
148,285
   
156,676
 
Unamortized Loss on Reacquired Debt
   
12,963
   
13,155
 
Other
   
44,147
   
25,691
 
Long-term Risk Management Assets
   
74,356
   
46,735
 
Deferred Property Taxes
   
48,816
   
64,754
 
Deferred Charges and Other
   
45,125
   
49,855
 
TOTAL
   
390,683
   
373,347
 
               
TOTAL ASSETS
 
$
2,979,877
 
$
3,029,896
 

See Notes to Financial Statements of Registrant Subsidiaries.




COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
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
   
577,669
   
577,415
 
 Retained Earnings
   
359,739
   
341,025
 
 Accumulated Other Comprehensive Income (Loss)
   
(66,590
)
 
(60,816
)
Total Common Shareholder’s Equity
   
911,844
   
898,650
 
Preferred Stock - No Shares Outstanding
   
-
   
-
 
Authorized - 2,500,000 shares at $100 par value
             
Authorized - 7,000,000 shares at $25 par value
             
Total Shareholder’s Equity
   
911,844
   
898,650
 
Long-term Debt:
             
Nonaffiliated
   
851,691
   
851,626
 
Affiliated
   
100,000
   
100,000
 
Total Long-term Debt
   
951,691
   
951,626
 
TOTAL
   
1,863,535
   
1,850,276
 
               
CURRENT LIABILITIES
             
Long-term Debt Due Within One Year - Nonaffiliated
   
36,000
   
36,000
 
Accounts Payable:
             
General
   
52,093
   
63,606
 
Affiliated Companies
   
35,523
   
45,745
 
Customer Deposits
   
31,063
   
24,890
 
Taxes Accrued
   
133,376
   
195,284
 
Interest Accrued
   
8,049
   
16,320
 
Risk Management Liabilities
   
70,672
   
42,172
 
Obligations Under Capital Leases
   
3,590
   
3,854
 
Other
   
16,485
   
24,338
 
TOTAL
   
386,851
   
452,209
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
459,333
   
464,545
 
Regulatory Liabilities:
             
Asset Removal Costs
   
104,889
   
103,104
 
Deferred Investment Tax Credits
   
27,272
   
27,933
 
Employee Benefits and Pension Obligations
   
49,801
   
62,778
 
Long-term Risk Management Liabilities
   
52,868
   
32,731
 
Obligations Under Capital Leases
   
8,060
   
8,660
 
Asset Retirement Obligations
   
11,799
   
11,585
 
Deferred Credits and Other
   
15,469
   
16,075
 
TOTAL
   
729,491
   
727,411
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
2,979,877
 
$
3,029,896
 
               

See Notes to Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
47,468
 
$
45,119
 
Adjustments to Reconcile Net Income to Net Cash Flows From (Used For) Operating Activities:
             
Depreciation and Amortization
   
38,198
   
36,818
 
Deferred Income Taxes
   
(2,613
)
 
7,726
 
Deferred Investment Tax Credits
   
(661
)
 
(752
)
Deferred Property Taxes
   
15,938
   
15,011
 
Pension and Postemployment Benefit Reserves
   
(366
)
 
(1,311
)
Mark-to-Market of Risk Management Contracts
   
(5,120
)
 
(6,766
)
Pension Contributions
   
(12,611
)
 
-
 
Gain on Sale of Assets
   
(1,130
)
 
(1,786
)
Change in Other Noncurrent Assets
   
(17,816
)
 
(4,878
)
Change in Other Noncurrent Liabilities
   
263
   
(2,054
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
14,059
   
23,091
 
Fuel, Materials and Supplies
   
7,529
   
(8,556
)
Accounts Payable
   
(21,735
)
 
(10,668
)
Taxes Accrued
   
(61,908
)
 
(7,718
)
Customer Deposits
   
6,173
   
6,047
 
Interest Accrued
   
(8,271
)
 
(6,583
)
Other Current Assets
   
(3,926
)
 
(831
)
Other Current Liabilities
   
(8,117
)
 
(1,058
)
Net Cash Flows From (Used For) Operating Activities
   
(14,646
)
 
80,851
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(33,042
)
 
(27,129
)
Change in Other Cash Deposits, Net
   
(7,125
)
 
7
 
Proceeds from Sale of Assets
   
1,825
   
2,105
 
Net Cash Flows Used For Investing Activities
   
(38,342
)
 
(25,017
)
               
FINANCING ACTIVITIES
             
Changes in Advances to/from Affiliates, Net
   
82,134
   
(24,575
)
Dividends Paid on Common Stock
   
(28,500
)
 
(31,250
)
Net Cash Flows From (Used For) Financing Activities
   
53,634
   
(55,825
)
               
Net Increase in Cash and Cash Equivalents
   
646
   
9
 
Cash and Cash Equivalents at Beginning of Period
   
25
   
3,377
 
Cash and Cash Equivalents at End of Period
 
$
671
 
$
3,386
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $21,898,000 and $18,971,000 and for income taxes was $57,037,000 and $(3,806,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $160,000 and $67,000 in 2005 and 2004, respectively.

See Notes to Respective Financial Statements.




COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to CSPCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to CSPCo.

 
   
Footnote
Reference
 
       
Significant Accounting Matters
 
 Note 1
 
New Accounting Pronouncements
 
 Note 2
 
Rate Matters
 
 Note 3
 
Customer Choice and Industry Restructuring
 
 Note 4
 
Commitments and Contingencies
 
 Note 5
 
Guarantees
 
 Note 6
 
Benefit Plans
 
 Note 8
 
Business Segments
 
 Note 9
 
Financing Activities
 
 Note 10
 


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 
 

 





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
43
 
               
Changes in Gross Margin:
             
Retail Margins
   
5
       
Transmission Revenues
   
(7
)
     
Off-system Sales
   
2
       
Other Revenues
   
1
       
Total Change in Gross Margin
         
1
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(6
)
     
Taxes Other Than Income Taxes
   
(2
)
     
Nonoperating Income and Expenses, Net
   
(4
)
     
Interest Charges
   
2
       
Total Change in Operating Expenses and Other
         
(10
)
               
Income Tax Expense
         
6
 
               
First Quarter of 2005 Net Income
       
$
40
 

Net Income decreased $3 million to $40 million in the first quarter of 2005. The key driver of the decrease was a $10 million net increase in operating and other expenses partially offset by a $6 million decrease in income taxes.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins increased $5 million primarily due to an $11 million increase in capacity settlement payments under the Interconnection Agreement related to the increase in an affiliate’s peak partially offset by a $6 million increase in unrecovered fuel costs.
·
Margins from Transmission Revenues decreased $7 million primarily due to the loss of through and out rates as mandated by the FERC.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $6 million primarily due to a $12 million increase in distribution maintenance mainly for storm damage expenses partially offset by the settlement and cancellation of the corporate owned life insurance policy in February 2005.
·
Taxes Other Than Income Taxes increased $2 million primarily due to a $1 million increase in property taxes and a $1 million increase in payroll-related taxes.
·
Nonoperating Income and Expenses, Net declined $4 million reflecting lower margins on risk management transactions.
·
Interest Charges decreased $2 million primarily due to lower long-term debt interest expense resulting from lower debt balances and lower interest rates.
 
Income Tax

The effective tax rates for the first quarter of 2005 and 2004 were 33.2% and 37.6%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to lower state and local income taxes and changes in permanent differences including COLI.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 
Moody’s
 
S&P
 
Fitch
           
Senior Unsecured Debt
Baa2
 
BBB
 
BBB

Cash Flow

Cash flows for the first three months of 2005 and 2004 were as follows:

   
2005
 
2004
 
   
(in thousands)
 
Cash and cash equivalents at beginning of period
 
$
465
 
$
3,899
 
Cash flows from (used for):
             
Operating activities
   
42,077
   
181,789
 
Investing activities
   
(60,537
)
 
(35,282
)
Financing activities
   
18,530
   
(147,177
)
Net increase (decrease) in cash and cash equivalents
   
70
   
(670
)
Cash and cash equivalents at end of period
 
$
535
 
$
3,229
 

Operating Activities

Our net cash flows from operating activities were $42 million for the first three months of 2005. We produced income of $40 million during the period including noncash expense items of $54 million for depreciation, amortization and accretion. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant were a $15 million contribution to our pension trust, an $81 million federal income tax payment and a net change in accounts receivable and payable of $11 million.

Our net cash flows from operating activities were $182 million in 2004. We produced Net Income of $43 million during the period and noncash expense items of $52 million for Depreciation, Amortization and Accretion. The other changes in assets and liabilities represent items that had a cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items; the most significant relates to Taxes Accrued. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP Consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments.

Investing Activities

Cash flows used for investing activities during 2005 were $61 million due to construction expenditures and a deposit to purchase emissions allowances. Construction expenditures were primarily incurred for nuclear generation, transmission and distribution assets to upgrade or replace equipment and improve reliability. For the remainder of 2005, we expect our Construction Expenditures to be approximately $270 million.

Our cash flows used for investing activities were $35 million in 2004 for construction.

Financing Activities

During the first quarter of 2005, we used cash of $61 million to retire preferred stock and $21 million to pay common dividends. These activities and our Construction Expenditures were supported by additional borrowing from the Money Pool of $101 million. There were no long-term debt issuances or retirements during the first quarter of 2005.

Our cash flows used for financing activities were $147 million in 2004. We used cash from operations to repay short-term debt and pay common dividends.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.

Off-Balance Sheet Arrangements

We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our current policy restricts the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements and sales of customer accounts receivable that are entered in the normal course of business. Our off-balance sheet arrangements have not changed significantly since year-end. For complete information on our off-balance sheet arrangements see “Off-balance Sheet Arrangements” in “Management’s Financial Discussion and Analysis” section of our 2004 Annual Report.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section  for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
34,573
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(74
)
Fair Value of New Contracts When Entered During the Period (b)
   
-
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
(233
)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
3,105
 
Total MTM Risk Management Contract Net Assets 
   
37,371
 
Net Cash Flow and Fair Value Hedge Contracts (f)
   
(7,971
)
DETM Assignment (g)
   
(12,342
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
17,058
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Hedges
 
DETM Assignment (b)
 
Total (c)
 
Current Assets
 
$
69,207
 
$
3,282
 
$
-
 
$
72,489
 
Noncurrent Assets
   
82,728
   
412
   
-
   
83,140
 
Total MTM Derivative Contract Assets
   
151,935
   
3,694
   
-
   
155,629
 
                           
Current Liabilities
   
(63,778
)
 
(10,333
)
 
(5,052
)
 
(79,163
)
Noncurrent Liabilities
   
(50,786
)
 
(1,332
)
 
(7,290
)
 
(59,408
)
Total MTM Derivative Contract Liabilities
   
(114,564
)
 
(11,665
)
 
(12,342
)
 
(138,571
)
                           
Total MTM Derivative Contract Net Assets
  (Liabilities)
 
$
37,371
 
$
(7,971
)
$
(12,342
)
$
17,058
 

(a)
Does not include Cash Flow and Fair Value Hedges.
(b)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009 (c)
 
Total (d)
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
(5,505
)
$
2,119
 
$
4,389
 
$
-
 
$
-
 
$
-
 
$
1,003
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
10,549
11,402
7,912
   
3,638
-
   
-
33,501
 
Prices Based on Models and Other Valuation Methods (b)
   
(202
)
 
(5,861
)
 
(4,233
)
 
3,010
   
5,378
   
4,775
   
2,867
 
Total
 
$
4,842
 
$
7,660
 
$
8,068
 
$
6,648
 
$
5,378
 
$
4,775
 
$
37,371
 

(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” is in 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.
(c)
There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $4.6 million of this mark-to-market value is in 2010.
(d)
Amounts exclude Cash Flow and Fair Value Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance December 31, 2004
 
$
1,558
 
$
(5,634
)
$
(4,076
)
Changes in Fair Value (a)
   
(4,272
)
 
-
   
(4,272
)
Reclassifications from AOCI to Net Income (b)
   
(2,184
)
 
143
   
(2,041
)
Ending Balance March 31, 2005
 
$
(4,898
)
$
(5,491
)
$
(10,389
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $5,062 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$360
 
$796
 
$390
 
$235
 
$371
 
$1,211
 
$522
 
$178
 

 
VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $53 million at both March 31, 2005 and December 31, 2004. We would not expect to liquidate our entire portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
361,592
 
$
353,822
 
Sales to AEP Affiliates
   
80,551
   
57,645
 
TOTAL
   
442,143
   
411,467
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
77,824
   
64,041
 
Purchased Electricity for Resale
   
11,272
   
6,363
 
Purchased Electricity from AEP Affiliates
   
74,009
   
63,128
 
Other Operation
   
90,976
   
100,850
 
Maintenance
   
54,322
   
38,042
 
Depreciation and Amortization
   
42,745
   
42,715
 
Taxes Other Than Income Taxes
   
17,507
   
15,216
 
Income Taxes
   
19,934
   
24,299
 
TOTAL
   
388,589
   
354,654
 
               
OPERATING INCOME
   
53,554
   
56,813
 
               
Nonoperating Income
   
17,497
   
20,588
 
Nonoperating Expenses
   
16,013
   
14,851
 
Nonoperating Income Tax Expense (Credit)
   
(237
)
 
1,613
 
Interest Charges
   
15,606
   
17,929
 
               
NET INCOME
   
39,669
   
43,008
 
               
Preferred Stock Dividend Requirements including Capital Stock Expense
   
118
   
118
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
39,551
 
$
42,890
 

The common stock of I&M is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.


 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
56,584
 
$
858,694
 
$
187,875
 
$
(25,106
)
$
1,078,047
 
                                 
Common Stock Dividends
               
(29,646
)
       
(29,646
)
Preferred Stock Dividends
               
(84
)
       
(84
)
Capital Stock Expense
         
34
   
(34
)
       
-
 
TOTAL
                           
1,048,317
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,127
                     
(2,093
)
 
(2,093
)
NET INCOME
               
43,008
         
43,008
 
TOTAL COMPREHENSIVE INCOME
                           
40,915
 
                                 
MARCH 31, 2004
 
$
56,584
 
$
858,728
 
$
201,119
 
$
(27,199
)
$
1,089,232
 
                                 
DECEMBER 31, 2004
 
$
56,584
 
$
858,835
 
$
221,330
 
$
(45,251
)
$
1,091,498
 
                                 
Common Stock Dividends
               
(21,000
)
       
(21,000
)
Preferred Stock Dividends
               
(85
)
       
(85
)
Capital Stock Expense
         
33
   
(33
)
       
-
 
TOTAL
                           
1,070,413
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $3,400
                     
(6,313
)
 
(6,313
)
NET INCOME
               
39,669
         
39,669
 
TOTAL COMPREHENSIVE INCOME
                           
33,356
 
                                 
MARCH 31, 2005
 
$
56,584
 
$
858,868
 
$
239,881
 
$
(51,564
)
$
1,103,769
 

See Notes to Financial Statements of Registrant Subsidiaries.
 


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
3,123,688
 
$
3,122,883
 
Transmission
   
1,008,687
   
1,009,551
 
Distribution
   
1,005,142
   
990,826
 
General (including nuclear fuel)
   
278,890
   
275,622
 
Construction Work in Progress
   
183,623
   
163,515
 
Total
   
5,600,030
   
5,562,397
 
Accumulated Depreciation and Amortization
   
2,629,388
   
2,603,479
 
TOTAL - NET
   
2,970,642
   
2,958,918
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
   
1,079,926
   
1,053,439
 
Nonutility Property, Net
   
49,731
   
50,440
 
Other Investments
   
13,251
   
21,848
 
TOTAL
   
1,142,908
   
1,125,727
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
535
   
465
 
Other Cash Deposits
   
8,005
   
46
 
Advances to Affiliates
   
-
   
5,093
 
Accounts Receivable:
             
Customers
   
61,822
   
62,608
 
Affiliated Companies
   
101,537
   
124,134
 
Miscellaneous
   
4,346
   
4,339
 
Allowance for Uncollectible Accounts
   
(76
)
 
(187
)
Fuel
   
21,219
   
27,218
 
Materials and Supplies
   
104,886
   
103,342
 
Risk Management Assets
   
72,489
   
52,141
 
Margin Deposits
   
9,184
   
5,400
 
Prepayments and Other
   
15,242
   
10,541
 
TOTAL
   
399,189
   
395,140
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
140,123
   
147,167
 
Incremental Nuclear Refueling Outage Expenses, Net
   
38,727
   
44,244
 
Unamortized Loss on Reacquired Debt
   
20,699
   
21,039
 
DOE Decontamination Fund
   
12,928
   
14,215
 
Other
   
48,426
   
31,015
 
Long-term Risk Management Assets
   
83,140
   
52,256
 
Emission Allowances
   
28,024
   
27,093
 
Deferred Property Taxes
   
31,461
   
22,372
 
Deferred Charges and Other Assets
   
18,381
   
28,955
 
TOTAL
   
421,909
   
388,356
 
               
TOTAL ASSETS
 
$
4,934,648
 
$
4,868,141
 

See Notes to Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
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
   
858,868
   
858,835
 
 Retained Earnings
   
239,881
   
221,330
 
 Accumulated Other Comprehensive Income (Loss)
   
(51,564
)
 
(45,251
)
Total Common Shareholder’s Equity
   
1,103,769
   
1,091,498
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
8,084
   
8,084
 
Total Shareholders’ Equity
   
1,111,853
   
1,099,582
 
Long-term Debt
   
1,314,137
   
1,312,843
 
TOTAL
   
2,425,990
   
2,412,425
 
               
CURRENT LIABILITIES
             
Cumulative Preferred Stock Due Within One Year
   
-
   
61,445
 
Advances from Affiliates
   
95,967
   
-
 
Accounts Payable:
             
General
   
92,019
   
91,472
 
Affiliated Companies
   
38,599
   
51,066
 
Customer Deposits
   
34,117
   
29,366
 
Taxes Accrued
   
76,868
   
123,159
 
Interest Accrued
   
22,072
   
12,465
 
Risk Management Liabilities
   
79,163
   
47,174
 
Obligations Under Capital Leases
   
5,730
   
6,124
 
Other
   
74,372
   
70,237
 
TOTAL
   
518,907
   
492,508
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
304,460
   
315,730
 
Regulatory Liabilities:
             
Asset Removal Costs
   
281,382
   
280,054
 
Deferred Investment Tax Credits
   
80,970
   
82,802
 
Excess ARO for Nuclear Decommissioning
   
259,825
   
245,175
 
Unrealized Gain on Forward Commitments
   
48,972
   
35,534
 
Other
   
30,832
   
33,695
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
   
65,545
   
66,472
 
Long-term Risk Management Liabilities
   
59,408
   
36,815
 
Obligations Under Capital Leases
   
40,380
   
44,608
 
Asset Retirement Obligations
   
723,433
   
711,769
 
Employee Benefits and Pension Obligations
   
55,999
   
70,027
 
Deferred Credits and Other
   
38,545
   
40,527
 
TOTAL
   
1,989,751
   
1,963,208
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
4,934,648
 
$
4,868,141
 

See Notes to Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
39,669
 
$
43,008
 
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
             
Depreciation and Amortization
   
42,745
   
42,715
 
Accretion Expense
   
11,664
   
9,698
 
Amortization, net of Deferrals of Incremental Nuclear
             
Refueling Outage Expenses
   
5,517
   
13,179
 
Deferred Income Taxes
   
(876
)
 
1,895
 
Deferred Investment Tax Credits
   
(1,832
)
 
(1,832
)
Deferred Property Taxes
   
(9,089
)
 
(7,959
)
Pension Contributions
   
(15,350
)
 
-
 
Mark-to-Market of Risk Management Contracts
   
(5,722
)
 
(7,396
)
Change in Other Noncurrent Assets
   
(1,214
)
 
(7,341
)
Change in Other Noncurrent Liabilities
   
(5,972
)
 
8,960
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
23,265
   
52,625
 
Fuel, Materials and Supplies
   
4,455
   
(7,335
)
Accounts Payable
   
(11,920
)
 
(29,218
)
Taxes Accrued
   
(46,291
)
 
37,754
 
Customer Deposits
   
4,751
   
8,873
 
Interest Accrued
   
9,607
   
5,007
 
Rent Accrued - Rockport Plant Unit 2
   
18,464
   
18,464
 
Other Current Assets
   
(5,072
)
 
1,006
 
Other Current Liabilities
   
(14,722
)
 
(314
)
Net Cash Flows From Operating Activities
   
42,077
   
181,789
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(52,749
)
 
(35,244
)
Change in Other Cash Deposits, Net
   
(7,959
)
 
(38
)
Proceeds from Sale of Assets
   
171
   
-
 
Net Cash Flows Used For Investing Activities
   
(60,537
)
 
(35,282
)
               
FINANCING ACTIVITIES
             
Retirement of Cumulative Preferred Stock
   
(61,445
)
 
(2,000
)
Changes in Advances to/from Affiliates, Net
   
101,060
   
(115,447
)
Dividends Paid on Common Stock
   
(21,000
)
 
(29,646
)
Dividends Paid on Cumulative Preferred Stock
   
(85
)
 
(84
)
Net Cash Flows From (Used For) Financing Activities
   
18,530
   
(147,177
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
70
   
(670
)
Cash and Cash Equivalents at Beginning of Period
   
465
   
3,899
 
Cash and Cash Equivalents at End of Period
 
$
535
 
$
3,229
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $5,035,000 and $12,007,000 and for income taxes was $82,338,000 and $(5,480,000) in 2005 and 2004, respectively. Noncash acquisitions under capital leases were $404,000 and $373,000 in 2005 and 2004, respectively.

See Notes to Respective Financial Statements.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to I&M’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to I&M.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments and Contingencies
Note 5
Guarantees
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Financing Activities
Note 10

 
 
 
 
 

 
 
 
 
 
 

 



 
 
 
 
 
 
 
 
 
 
 
 

 

KENTUCKY POWER COMPANY

 
 
 
 
 
 
 
 

 






KENTUCKY POWER COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income        
$
12
 
               
Changes in Gross Margin:
             
Retail Margins
   
(4
)
     
Off-system Sales
   
4
       
Transmission Revenues
   
(2
)
     
Other Revenues
   
(2
)
     
Total Change in Gross Margin
         
(4
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
-
       
Depreciation and Amortization
   
-
       
Taxes Other Than Income Taxes
   
-
       
Nonoperating Income and Expenses, Net
   
-
       
Interest Charges
   
-
       
Total Change in Operating Expenses and Other
         
-
 
               
Income Tax Expense
         
2
 
               
First Quarter of 2005 Net Income
       
$
10
 

Net Income decreased $2 million to $10 million in the first quarter of 2005. The key driver of the decrease was a $4 million decrease in gross margin partially offset by a $2 million decrease in income taxes.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins decreased by $4 million in comparison to 2004 primarily due to our higher MLR share caused by the increase in our peak demand established in both December 2004 and January 2005 resulting in a $4 million increase in capacity settlement payments under the Interconnection Agreement.
·
Margins from Off-system Sales for 2005 increased by $4 million in comparison to 2004 primarily due to higher sales volumes as well as higher optimization activity.
·
Margins from Transmission Revenues decreased $2 million primarily due to the elimination of $3 million of revenues related to through and out rates partially offset by an increase of $1 million in unbundled transmission revenues due to the addition of SECA rates as mandated by the FERC.
·
Margins from Other Revenues decreased $2 million primarily due to a $3 million adjustment of the Demand Side Management Program regulatory asset in March 2005.

Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were 29.1% and 35.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in various permanent and flow-through temporary differences and lower state and local income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 
Moody’s
 
S&P
 
Fitch
           
Senior Unsecured Debt
Baa2
 
BBB
 
BBB

Financing Activity

Long-term debt issuances and retirements during the first three months of 2005 were:

Issuances

None

Retirements

Notes Payable-Affiliated of $20 million with an interest rate of 6.50% was retired on April 15, 2005.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section  for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
12,691
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(78
)
Fair Value of New Contracts When Entered During the Period (b)
   
-
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
276
 
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
2,655
 
Total MTM Risk Management Contract Net Assets
   
15,544
 
Net Cash Flow and Fair Value Hedge Contracts (f)
   
(3,480
)
DETM Assignment (g)
   
(5,133
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
6,931
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
 
 

Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Hedges
 
DETM Assignment (b)
 
Total (c)
 
Current Assets
 
$
28,786
 
$
1,552
 
$
-
 
$
30,338
 
Noncurrent Assets
   
34,410
   
171
   
-
   
34,581
 
Total MTM Derivative Contract Assets
   
63,196
   
1,723
   
-
   
64,919
 
                           
Current Liabilities
   
(26,528
)
 
(4,239
)
 
(2,101
)
 
(32,868
)
Noncurrent Liabilities
   
(21,124
)
 
(964
)
 
(3,032
)
 
(25,120
)
Total MTM Derivative Contract Liabilities
   
(47,652
)
 
(5,203
)
 
(5,133
)
 
(57,988
)
                           
Total MTM Derivative Contract Net Assets
  (Liabilities)
 
$
15,544
 
$
(3,480
)
$
(5,133
)
$
6,931
 

(a)
Does not include Cash Flow and Fair Value Hedges.
(b)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009 (c)
 
Total (d)
 
Prices Actively Quoted - Exchange Traded
  Contracts
 
$
(2,290
)
$
882
 
$
1,826
 
$
-
 
$
-
 
$
-
 
$
418
 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
   
4,388
   
4,743
   
3,291
   
1,514
   
-
   
-
   
13,936
 
Prices Based on Models and Other Valuation
  Methods (b)
   
(88
)
 
(2,438
)
 
(1,760
)
 
1,253
   
2,237
   
1,986
   
1,190
 
Total
 
$
2,010
 
$
3,187
 
$
3,357
 
$
2,767
 
$
2,237
 
$
1,986
 
$
15,544
 

(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” is in 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.
(c)
There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $1.9 million of this mark-to-market value is in 2010.
(d)
Amounts exclude Cash Flow and Fair Value Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate swap transactions in order to manage interest rate risk to existing floating rate debt. We do not hedge all interest rate risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance December 31, 2004
 
$
569
 
$
244
 
$
813
 
Changes in Fair Value (a)
   
(1,702
)
 
-
   
(1,702
)
Reclassifications from AOCI to Net Income (b)
   
(903
)
 
(22
)
 
(925
)
Ending Balance March 31, 2005
 
$
(2,036
)
$
222
 
$
(1,814
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,782 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$150
 
$331
 
$162
 
$98
 
$135
 
$442
 
$191
 
$65
 

VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $16 million at both March 31, 2005 and December 31, 2004. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or financial position.



KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
115,660
 
$
107,046
 
Sales to AEP Affiliates
   
12,189
   
6,612
 
TOTAL
   
127,849
   
113,658
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
27,892
   
20,894
 
Purchased Electricity from AEP Affiliates
   
44,863
   
33,306
 
Other Operation
   
14,560
   
13,272
 
Maintenance
   
5,916
   
7,325
 
Depreciation and Amortization
   
11,152
   
10,859
 
Taxes Other Than Income Taxes
   
2,425
   
2,328
 
Income Taxes
   
4,008
   
6,460
 
TOTAL
   
110,816
   
94,444
 
               
OPERATING INCOME
   
17,033
   
19,214
 
               
Nonoperating Income
   
445
   
952
 
Nonoperating Expenses
   
171
   
1,313
 
Nonoperating Income Tax Expense (Credit)
   
52
   
(127
)
Interest Charges
   
7,370
   
7,369
 
               
NET INCOME
 
$
9,885
 
$
11,611
 
               

The common stock of KPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
50,450
 
$
208,750
 
$
64,151
 
$
(6,213
)
$
317,138
 
                                 
Common Stock Dividends
               
(6,250
)
       
(6,250
)
TOTAL
                           
310,888
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $406
                     
(754
)
 
(754
)
NET INCOME
               
11,611
         
11,611
 
TOTAL COMPREHENSIVE INCOME
                           
10,857
 
                                 
MARCH 31, 2004
 
$
50,450
 
$
208,750
 
$
69,512
 
$
(6,967
)
$
321,745
 
                                 
DECEMBER 31, 2004
 
$
50,450
 
$
208,750
 
$
70,555
 
$
(8,775
)
$
320,980
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,415
                     
(2,627
)
 
(2,627
)
NET INCOME
               
9,885
         
9,885
 
TOTAL COMPREHENSIVE INCOME
                           
7,258
 
                                 
MARCH 31, 2005
 
$
50,450
 
$
208,750
 
$
80,440
 
$
(11,402
)
$
328,238
 

See Notes to Financial Statements of Registrant Subsidiaries.
 


KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
464,637
 
$
462,641
 
Transmission
   
385,912
   
385,667
 
Distribution
   
442,925
   
438,766
 
General
   
58,979
   
57,929
 
Construction Work in Progress
   
14,702
   
16,544
 
Total
   
1,367,155
   
1,361,547
 
Accumulated Depreciation and Amortization
   
406,584
   
398,455
 
TOTAL - NET
   
960,571
   
963,092
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
5,437
   
5,438
 
Other Investments
   
351
   
422
 
TOTAL
   
5,788
   
5,860
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
276
   
127
 
Other Cash Deposits
   
3,319
   
5
 
Advances to Affiliates
   
24,734
   
16,127
 
Accounts Receivable:
             
Customers
   
24,674
   
22,130
 
Affiliated Companies
   
23,232
   
23,046
 
Accrued Unbilled Revenues
   
5,703
   
7,340
 
Miscellaneous
   
109
   
94
 
Allowance for Uncollectible Accounts
   
(9
)
 
(34
)
Fuel
   
8,111
   
6,551
 
Materials and Supplies
   
8,698
   
9,385
 
Risk Management Assets
   
30,338
   
19,845
 
Margin Deposits
   
3,760
   
1,960
 
Prepayments and Other
   
3,294
   
1,782
 
TOTAL
   
136,239
   
108,358
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
100,954
   
103,849
 
Other
   
22,875
   
14,558
 
Long-term Risk Management Assets
   
34,581
   
19,067
 
Emission Allowances
   
10,714
   
9,666
 
Deferred Property Taxes
   
5,408
   
7,036
 
Deferred Charges and Other
   
8,256
   
11,761
 
TOTAL
   
182,788
   
165,937
 
               
TOTAL ASSETS
 
$
1,285,386
 
$
1,243,247
 

See Notes to Financial Statements of Registrant Subsidiaries.




KENTUCKY POWER COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
Common Shareholder’s Equity:
             
Common Stock - $50 par value per share:
             
 Authorized - 2,000,000 shares
             
 Outstanding - 1,009,000 shares
 
$
50,450
 
$
50,450
 
 Paid-in Capital
   
208,750
   
208,750
 
 Retained Earnings
   
80,440
   
70,555
 
 Accumulated Other Comprehensive Income (Loss)
   
(11,402
)
 
(8,775
)
Total Common Shareholder’s Equity
   
328,238
   
320,980
 
Long-term Debt:
             
Nonaffiliated
   
427,375
   
428,310
 
Affiliated
   
80,000
   
80,000
 
Total Long-term Debt
   
507,375
   
508,310
 
TOTAL
   
835,613
   
829,290
 
               
CURRENT LIABILITIES
             
Accounts Payable:
             
General
   
23,975
   
20,080
 
Affiliated Companies
   
21,075
   
24,899
 
Risk Management Liabilities
   
32,868
   
17,205
 
Taxes Accrued
   
11,663
   
9,248
 
Interest Accrued
   
8,992
   
6,754
 
Customer Deposits
   
15,709
   
12,309
 
Obligations Under Capital Leases
   
1,458
   
1,561
 
Other
   
8,304
   
9,038
 
TOTAL
   
124,044
   
101,094
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
224,214
   
227,536
 
Regulatory Liabilities:
             
Asset Removal Costs
   
29,214
   
28,232
 
Deferred Investment Tax Credits
   
6,430
   
6,722
 
Other Regulatory Liabilities
   
22,982
   
15,622
 
Employee Benefits and Pension Obligations
   
14,714
   
17,729
 
Long-term Risk Management Liabilities
   
25,120
   
13,484
 
Obligations Under Capital Leases
   
2,577
   
2,802
 
Deferred Credits
   
478
   
736
 
TOTAL
   
325,729
   
312,863
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
1,285,386
 
$
1,243,247
 

See Notes to Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
9,885
 
$
11,611
 
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
             
Depreciation and Amortization
   
11,152
   
10,859
 
Deferred Income Taxes
   
988
   
3,442
 
Deferred Investment Tax Credits
   
(292
)
 
(292
)
Deferred Property Taxes
   
1,628
   
1,581
 
Pension Contributions
   
(3,045
)
 
-
 
Pension and Postemployment Benefit Reserves
   
30
   
(377
)
Mark-to-Market of Risk Management Contracts
   
(3,290
)
 
(2,135
)
Over/Under Fuel Recovery
   
(5,203
)
 
(988
)
Loss on Sale of Assets
   
-
   
1,051
 
Change in Other Noncurrent Assets
   
94
   
(7,219
)
Change in Other Noncurrent Liabilities
   
4,413
   
8,274
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
(1,133
)
 
8,202
 
Fuel, Materials and Supplies
   
(873
)
 
(2,772
)
Accounts Payable
   
71
   
3,266
 
Taxes Accrued
   
2,415
   
5,027
 
Customer Deposits
   
3,400
   
2,564
 
Interest Accrued
   
2,238
   
1,970
 
Other Current Assets
   
(2,234
)
 
798
 
Other Current Liabilities
   
(833
)
 
(1,190
)
Net Cash Flows From Operating Activities
   
19,411
   
43,672
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(7,341
)
 
(7,374
)
Change in Other Cash Deposits, Net
   
(3,314
)
 
(15
)
Proceeds from Sale of Assets
   
-
   
1,538
 
Net Cash Flows Used For Investing Activities
   
(10,655
)
 
(5,851
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Affiliated
   
-
   
20,000
 
Changes in Advances to/from Affiliates, Net
   
(8,607
)
 
(51,238
)
Dividends Paid on Common Stock
   
-
   
(6,250
)
Net Cash Flows Used For Financing Activities
   
(8,607
)
 
(37,488
)
               
Net Increase in Cash and Cash Equivalents
   
149
   
333
 
Cash and Cash Equivalents at Beginning of Period
   
127
   
863
 
Cash and Cash Equivalents at End of Period
 
$
276
 
$
1,196
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $3,570,000 and $5,104,000 and for income taxes was $691,000 and $(833,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 were $126,000.

See Notes to Respective Financial Statements.



KENTUCKY POWER COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to KPCo’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to KPCo.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments and Contingencies
Note 5
Guarantees
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Financing Activities
Note 10
 
 
 
 
 
 
 
 
 
 
 
 
 

 




 
 
 
 
 
 
 
 
 
 
 
 
 

 

OHIO POWER COMPANY CONSOLIDATED


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 



OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
80
 
               
Changes in Gross Margin:
             
Retail Margins
   
(7
)
     
Transmission Revenues
   
(7
)
     
Off-system Sales
   
5
       
Total Change in Gross Margin
         
(9
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
5
       
Depreciation and Amortization
   
(2
)
     
Nonoperating Income and Expenses, Net
   
23
       
Interest Charges
   
6
       
Total Change in Operating Expenses and Other
         
32
 
               
Income Tax Expense
         
(4
)
               
First Quarter of 2005 Net Income
       
$
99
 

Net Income increased $19 million in the first quarter of 2005. The key driver of the increase was a $32 million net decrease in operating expenses and other partially offset by a $9 million decrease in gross margin.

The major components of our decrease in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins were $7 million less than the prior period primarily due to higher fuel costs.
·
Margins from Transmission Revenues decreased $7 million primarily due to the loss of through and out rates as mandated by the FERC. The decrease was partially offset by an increase in unbundled transmission revenues due to the addition of SECA rates.
·
Margins from Off-system Sales increased $5 million primarily due to favorable optimization activity and increased sales volumes.

Operating Expenses and Other changed between years as follows:

·
Nonoperating Income and Expenses, Net increased $23 million primarily due to an establishment of a regulatory asset for carrying costs on environmental capital expenditures of $22 million as a result of the recent PUCO rate stabilization plan order.
·
Interest Charges decreased by $6 million primarily due to refinancing debt maturities and optional redemptions with lower cost debt.
·
Other Operation and Maintenance expenses decreased $5 million primarily due to the settlement and cancellation of the corporate owned life insurance policy of $7 million in February 2005, a decrease in administrative expenses of $4 million related to the Gavin Scrubber, the establishment of a regulatory asset for PJM administrative fees of $2 million and decreases in employee benefit expenses and administrative and support expenses offset by a $10 million increase in expense from a major ice storm in January 2005.

Income Tax

The effective tax rates for the first quarter of 2005 and 2004 were 33.1% and 36.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences including COLI.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 
Moody’s
 
S&P
 
Fitch
           
Senior Unsecured Debt
A3
 
BBB
 
BBB+

Cash Flow

Cash flows for the three months ended March 31, 2005 and 2004 were as follows:

   
2005
 
2004
 
   
(in thousands)
 
Cash and cash equivalents at beginning of period
 
$
9,300
 
$
7,233
 
Cash flows from (used for):
             
Operating activities
   
74,821
   
125,131
 
Investing activities
   
(144,208
)
 
2,187
 
Financing activities
   
61,170
   
(123,792
)
Net increase (decrease) in cash and cash equivalents
   
(8,217
)
 
3,526
 
Cash and cash equivalents at end of period
 
$
1,083
 
$
10,759
 

Operating Activities

Our net cash flows from operating activities were $74 million for the first three months of 2005. We produced income of $99 million during the period and a noncash expense item of $74 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital primarily relates to a $73 million decrease in Taxes Accrued due to a 2004 federal income tax payment made in the first quarter of 2005.

Our net cash flows from operating activities were $125 million for the first three months of 2004. We produced income of $80 million during the period and a noncash expense item of $72 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items; none of which were significant.

Investing Activities

Our net cash flows used for investing activities for the first three months of 2005 were $144 million primarily due to Construction Expenditures and a deposit to purchase emissions allowances. Construction expenditures were focused primarily on environmental upgrades, as well as projects to improve service reliability for transmission and distribution. For the remainder of 2005, we expect our Construction Expenditures to be approximately $632 million.

Our net cash flows from investing activities for the first three months of 2004 were $2 million. The change is primarily due to a cash deposit that we used to redeem $50 million of debt in January 2004 offset by construction expenditures.

Financing Activities

Our net cash flows from financing activities during the first three months of 2005 were $61 million primarily due to increased repayment of borrowings from the AEP Utility Money Pool.

Our net cash flows used for financing activities during the first three months of 2004 were $124 million primarily due to decreased repayments of borrowings from the AEP Utility Money Pool and dividend payments on Common Stock.

Financing Activity

In January 2005, we redeemed $5 million of 5.90% Cumulative Preferred Stock Subject to Mandatory Redemption. Additionally, long-term debt issuances and retirements during the three months ended March 31, 2005 were:

Issuances

   
Principal
 
Interest
 
Due
Type of Debt
 
Amount
 
Rate
 
Date
   
(in thousands)
 
(%)
   
Installment Purchase Contracts
 
$54,500
 
Variable
 
2029
Installment Purchase Contracts
 
  54,500
 
Variable
 
2028
Installment Purchase Contracts
 
  54,500
 
Variable
 
2028
Installment Purchase Contracts
 
  54,500
 
Variable
 
2028

Retirements and Principal Payments

   
Principal
 
Interest
 
Due
Type of Debt
 
Amount
 
Rate
 
Date
   
(in thousands)
 
(%)
   
Installment Purchase Contracts
 
$51,000
 
6.375
 
2029
Installment Purchase Contracts
 
  51,000
 
6.375
 
2029
Installment Purchase Contracts
 
  40,000
 
Variable
 
2028
Installment Purchase Contracts
 
  40,000
 
Variable
 
2028
Installment Purchase Contracts
 
  18,000
 
Variable
 
2029
Installment Purchase Contracts
 
  18,000
 
Variable
 
2029
Notes Payable
 
    1,463
 
6.81  
 
2008
Notes Payable
 
    3,250
 
6.27  
 
2009

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section  for additional discussion of factors relevant to us.
 
Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
47,777
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(11,363
)
Fair Value of New Contracts When Entered During the Period (b)
   
374
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
9,814
 
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
-
 
Total MTM Risk Management Contract Net Assets
   
46,602
 
Net Cash Flow Hedge Contracts (f)
   
(9,770
)
DETM Assignment (g)
   
(15,413
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
21,419
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
 

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Cash Flow
Hedges
 
DETM
Assignment
(b)
 
Total (c)
 
Current Assets
 
$
99,111
 
$
6,303
 
$
-
 
$
105,414
 
Noncurrent Assets
   
106,219
   
811
   
-
   
107,030
 
Total MTM Derivative Contract Assets
   
205,330
   
7,114
   
-
   
212,444
 
                           
Current Liabilities
   
(91,128
)
 
(15,588
)
 
(6,309
)
 
(113,025
)
Noncurrent Liabilities
   
(67,600
)
 
(1,296
)
 
(9,104
)
 
(78,000
)
                         
Total MTM Derivative Contract
  Liabilities
(158,728
)
 
(16,884
)
 
(15,413
)
 
(191,025
)
                           
Total MTM Derivative Contract Net
 
 
$
 
46,602
 
$
(9,770
)
$
(15,413
)
$
21,419
 
  Assets (Liabilities)
 
(a)
Does not include Cash Flow Hedges.
(b)
See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk
Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009 (c)
 
Total (d)
 
Prices Actively Quoted - Exchange Traded
  Contracts
 
$
(6,874
)
$
2,647
 
$
5,481
 
$
-
 
$
-
 
$
-
 
$
1,254
 
Prices Provided by Other External Sources -  OTC Broker Quotes (a)
   
16,284
   
11,207
   
10,584
   
4,544
   
-
   
-
   
42,619
 
Prices Based on Models and Other Valuation
  Methods (b)
   
(508
)
 
(7,876
)
 
(5,324
)
 
3,759
   
6,716
   
5,962
   
2,729
 
Total
 
$
8,902
 
$
5,978
 
$
10,741
 
$
8,303
 
$
6,716
 
$
5,962
 
$
46,602
 

(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” is in 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.
(c)
There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $5.7 million of this mark-to-market value is in 2010.
(d)
Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Foreign
Currency
 
Total
 
Beginning Balance December 31, 2004
 
$
1,599
 
$
(358
)
$
1,241
 
Changes in Fair Value (a)
   
(5,476
)
 
-
   
(5,476
)
Reclassifications from AOCI to Net Income (b)
   
(2,463
)
 
3
   
(2,460
)
Ending Balance March 31, 2005
 
$
(6,340
)
$
(355
)
$
(6,695
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $6,040 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$449
 
$994
 
$488
 
$294
 
$464
 
$1,513
 
$652
 
$223
 

VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $155 million and $146 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.



OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
456,231
 
$
443,729
 
Sales to AEP Affiliates
   
151,839
   
146,488
 
TOTAL
   
608,070
   
590,217
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
180,261
   
166,271
 
Purchased Electricity for Resale
   
18,762
   
12,183
 
Purchased Electricity from AEP Affiliates
   
25,618
   
19,303
 
Other Operation
   
73,783
   
91,096
 
Maintenance
   
45,755
   
34,051
 
Depreciation and Amortization
   
73,947
   
71,782
 
Taxes Other Than Income Taxes
   
47,142
   
47,190
 
Income Taxes
   
38,571
   
39,982
 
TOTAL
   
503,839
   
481,858
 
               
OPERATING INCOME
   
104,231
   
108,359
 
               
Nonoperating Income
   
54,972
   
16,751
 
Carrying Costs Income
   
22,037
   
179
 
Nonoperating Expenses
   
45,027
   
8,069
 
Nonoperating Income Tax Expense
   
10,567
   
5,087
 
Interest Charges
   
26,163
   
31,969
 
               
NET INCOME
   
99,483
   
80,164
 
               
Preferred Stock Dividend Requirements
   
183
   
183
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
99,300
 
$
79,981
 

The common stock of OPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.
 


OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
321,201
 
$
462,484
 
$
729,147
 
$
(48,807
)
$
1,464,025
 
                                 
Common Stock Dividends
               
(57,057
)
       
(57,057
)
Preferred Stock Dividends
               
(183
)
       
(183
)
TOTAL
                           
1,406,785
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,358
                     
(2,522
)
 
(2,522
)
Minimum Pension Liability, Net of Tax of  $2,123
                     
(3,942
)
 
(3,942
)
NET INCOME
               
80,164
         
80,164
 
TOTAL COMPREHENSIVE INCOME
                           
73,700
 
                                 
MARCH 31, 2004
 
$
321,201
 
$
462,484
 
$
752,071
 
$
(55,271
)
$
1,480,485
 
                                 
DECEMBER 31, 2004
 
$
321,201
 
$
462,485
 
$
764,416
 
$
(74,264
)
$
1,473,838
 
                                 
Common Stock Dividends
               
(7,500
)
       
(7,500
)
Preferred Stock Dividends
               
(183
)
       
(183
)
TOTAL
                           
1,466,155
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $4,273
                     
(7,936
)
 
(7,936
)
NET INCOME
               
99,483
         
99,483
 
TOTAL COMPREHENSIVE INCOME
                           
91,547
 
                                 
MARCH 31, 2005
 
$
321,201
 
$
462,485
 
$
856,216
 
$
(82,200
)
$
1,557,702
 

See Notes to Financial Statements of Registrant Subsidiaries.




OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
           
Production
 
$
4,137,431
 
$
4,127,284
 
Transmission
   
984,702
   
978,492
 
Distribution
   
1,213,373
   
1,202,550
 
General
   
242,690
   
248,749
 
Construction Work in Progress
   
329,393
   
240,957
 
Total
   
6,907,589
   
6,798,032
 
Accumulated Depreciation and Amortization
   
2,641,778
   
2,617,238
 
TOTAL - NET
   
4,265,811
   
4,180,794
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
44,743
   
44,774
 
Other
   
8,901
   
13,409
 
TOTAL
   
53,644
   
58,183
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
1,083
   
9,300
 
Other Cash Deposits
   
9,986
   
37
 
Advances to Affiliates
   
41,407
   
125,971
 
Accounts Receivable:
             
Customers
   
112,135
   
109,592
 
Affiliated Companies
   
147,532
   
144,175
 
Miscellaneous
   
27,144
   
7,626
 
Allowance for Uncollectible Accounts
   
(37
)
 
(93
)
Fuel
   
69,506
   
70,309
 
Materials and Supplies
   
56,855
   
55,569
 
Emissions Allowances
   
48,097
   
95,303
 
Risk Management Assets
   
105,414
   
79,541
 
Margin Deposits
   
11,926
   
7,056
 
Prepayments and Other
   
16,598
   
10,492
 
TOTAL
   
647,646
   
714,878
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
171,688
   
169,866
 
Transition Regulatory Assets
   
202,908
   
225,273
 
Unamortized Loss on Reacquired Debt
   
10,866
   
11,046
 
Other
   
65,433
   
22,189
 
Long-term Risk Management Assets
   
107,030
   
66,727
 
Deferred Property Taxes
   
54,556
   
70,214
 
Deferred Charges and Other Assets
   
63,973
   
74,095
 
TOTAL
   
676,454
   
639,410
 
               
TOTAL ASSETS
 
$
5,643,555
 
$
5,593,265
 

See Notes to Financial Statements of Registrant Subsidiaries.




OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)
 
   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
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
   
462,485
   
462,485
 
 Retained Earnings
   
856,216
   
764,416
 
 Accumulated Other Comprehensive Income (Loss)
   
(82,200
)
 
(74,264
)
Total Common Shareholder’s Equity
   
1,557,702
   
1,473,838
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
16,641
   
16,641
 
Total Shareholders’ Equity
   
1,574,343
   
1,490,479
 
Long-term Debt:
             
Nonaffiliated
   
1,594,364
   
1,598,706
 
Affiliated
   
400,000
   
400,000
 
Total Long-term Debt
   
1,994,364
   
1,998,706
 
TOTAL
   
3,568,707
   
3,489,185
 
               
Minority Interest
   
13,475
   
14,083
 
               
CURRENT LIABILITIES
             
Short-term Debt - Nonaffiliated
   
18,702
   
23,498
 
Long-term Debt Due Within One Year - Nonaffiliated
   
12,354
   
12,354
 
Cumulative Preferred Stock Subject to Mandatory Redemption
   
-
   
5,000
 
Accounts Payable:
             
General
   
190,301
   
143,247
 
Affiliated Companies
   
60,079
   
116,615
 
Customer Deposits
   
30,991
   
22,620
 
Taxes Accrued
   
159,776
   
233,026
 
Interest Accrued
   
23,045
   
39,254
 
Risk Management Liabilities
   
113,025
   
70,311
 
Obligations Under Capital Leases
   
8,806
   
9,081
 
Other
   
71,539
   
74,977
 
TOTAL
   
688,618
   
749,983
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
945,105
   
943,465
 
Regulatory Liabilities:
             
Asset Removal Costs
   
105,503
   
102,875
 
Deferred Investment Tax Credits
   
12,290
   
12,539
 
Long-term Risk Management Liabilities
   
78,000
   
46,261
 
Deferred Credits
   
43,280
   
24,377
 
Employee Benefits and Pension Obligations
   
106,201
   
126,825
 
Obligations Under Capital Leases
   
29,867
   
31,652
 
Asset Retirement Obligations
   
46,494
   
45,606
 
Other
   
6,015
   
6,414
 
TOTAL
   
1,372,755
   
1,340,014
 
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
5,643,555
 
$
5,593,265
 

See Notes to Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
99,483
 
$
80,164
 
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
             
Depreciation and Amortization
   
73,947
   
71,782
 
Deferred Income Taxes
   
4,092
   
7,701
 
Deferred Investment Tax Credits
   
(249
)
 
(761
)
Deferred Property Taxes
   
15,658
   
14,745
 
Pension and Postemployment Benefit Reserves
   
(617
)
 
4,160
 
Mark-to-Market of Risk Management Contracts
   
(2,477
)
 
(5,729
)
Pension Contributions
   
(20,007
)
 
-
 
Carrying Costs Income
   
(22,037
)
 
(179
)
Change in Other Noncurrent Assets
   
(12,780
)
 
(11,116
)
Change in Other Noncurrent Liabilities
   
19,811
   
(2,682
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
(25,474
)
 
(13,886
)
Fuel, Materials and Supplies
   
(483
)
 
2,743
 
Accounts Payable
   
(9,482
)
 
(21,674
)
Taxes Accrued
   
(73,250
)
 
18,336
 
Customer Deposits
   
8,371
   
10,280
 
Interest Accrued
   
(16,209
)
 
(16,934
)
Other Current Assets
   
40,237
   
618
 
Other Current Liabilities
   
(3,713
)
 
(12,437
)
Net Cash Flows From Operating Activities
   
74,821
   
125,131
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(134,848
)
 
(49,868
)
Change in Other Cash Deposits, Net
   
(9,949
)
 
50,953
 
Proceeds from Sale of Assets
   
589
   
1,102
 
Net Cash Flows From (Used For) Investing Activities
   
(144,208
)
 
2,187
 
               
FINANCING ACTIVITIES
             
Change in Short-term Debt, Net
   
(4,796
)
 
631
 
Issuance of Long-term Debt
   
216,798
   
-
 
Issuance of Long-term Debt- Affiliated
   
-
   
200,000
 
Retirement of Long-term Debt- Nonaffiliated
   
(222,713
)
 
(192,963
)
Retirement of Cumulative Preferred Stock
   
(5,000
)
 
(2,250
)
Changes in Advances to/from Affiliates, Net
   
84,564
   
(71,970
)
Dividends Paid on Common Stock
   
(7,500
)
 
(57,057
)
Dividends Paid on Cumulative Preferred Stock
   
(183
)
 
(183
)
Net Cash Flows From (Used For) Financing Activities
   
61,170
   
(123,792
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
(8,217
)
 
3,526
 
Cash and Cash Equivalents at Beginning of Period
   
9,300
   
7,233
 
Cash and Cash Equivalents at End of Period
 
$
1,083
 
$
10,759
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $37,519,000 and $46,636,000 and for income taxes was $87,763,000 and $(8,644,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $555,000 and $0 in 2005 and 2004, respectively.

See Notes to Respective Financial Statements.



OHIO POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to OPCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to OPCo.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Customer Choice and Industry Restructuring
Note 4
Commitments and Contingencies
Note 5
Guarantees
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Financing Activities
Note 10


 
 
 
 
 
 
 
 
 
 

 




 
 
 
 
 
 
 
 
 
 
 
 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 






PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
(9
)
               
Changes in Gross Margin:
             
Retail Margins
   
(4
)
     
Off-system Sales
   
3
       
Total Change in Gross Margin
         
(1
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
15
       
Depreciation and Amortization
   
(1
)
     
Interest Charges
   
2
       
Total Change in Operating Expenses and Other
         
16
 
               
Income Tax Expense
         
(6
)
               
First Quarter of 2005 Net Income
       
$
-
 

Net Income increased $9 million in the first quarter of 2005. The key drivers of the increase were a $16 million decrease in operating expenses and other partially offset by a $6 million increase in income taxes and a $1 million decrease in gross margin.  Fluctuations occurring in retail fuel revenues generally do not impact operating income, as they are offset in the retail portion of fuel and purchased power expense due to the functioning of the fuel adjustment clause in Oklahoma.

The major components of our decrease in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins decreased by $4 million in comparison to 2004 primarily due to a $1 million decrease in retail sales due to slightly lower volumes and a $2 million decrease in net fuel revenue/fuel expense.
·
Margins from Off-system Sales for 2005 increased by $3 million in comparison to 2004 primarily due to higher sales volumes of approximately 9% as well as higher optimization activity.

Operating Expenses and Other decreased between years as follows:

·
Other Operation and Maintenance expenses decreased $15 million. Transmission related expenses decreased $6 million primarily due to a prior year unfavorable adjustment for affiliated OATT and ancillary services resulting from revised ERCOT data for the years 2001 through 2003 of approximately $5 million. Distribution expenses decreased $2 million resulting primarily from a 2004 labor settlement. Administrative and general expenses decreased approximately $6 million due to lower outside service and employee related expenses, while customer related expenses increased $1 million. Maintenance expenses decreased $2 million primarily due to higher 2004 cost of scheduled plant maintenance offset in part by increased maintenance of overhead lines.
·
Interest Charges decreased $2 million primarily due to the retirement of higher rate First Mortgage Bonds replaced by lower rate Senior Unsecured Notes and the retirement of Trust Preferred Securities in 2004.
 
Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were 184.9% and 46.2%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate from the comparative period is primarily due to higher pre-tax income in 2005 and federal income tax adjustments.

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
 
A-
 
A
Senior Unsecured Debt
Baa1
 
BBB
 
A-

Financing Activity

There were no long-term debt issuances or retirements during the first three months of 2005.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.

Significant Factors

Oklahoma Regulatory Activity

PSO Rate Review

We are involved in a commission staff-initiated rate review before the OCC seeking to increase our base rates, while various other parties made recommendations to reduce our base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. Pending approval by the OCC, the settlement provides for a $7 million base rate reduction partially offset by a $6 million reduction in annual depreciation expense. The settlement also provides for recovery of $9 million of deferred fuel and the continuation of the vegetation management rider. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. Finally, the settlement stipulates that we may not file for a base rate increase before April 1, 2006. The OCC did not approve the settlement in time for implementation of new base rates in May 2005 as agreed to by the parties, which voids the settlement. The OCC issued an Order approving the stipulation on May 2, 2005 with one exception. The Order approves the implementation of new base rates in June 2005 versus the stipulation date of May 2005.

PSO Fuel and Purchased Power

In 2002, we experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, we submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending we recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of our 2001 fuel and purchased power practices.

In the proceeding, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and AEP West companies should have received more margins. The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. Using the intervenors’ method, we estimate that the increase in margins would be $29 million through March 31, 2005. In April 2005, the OCC heard arguments from intervenors that requested the OCC to conduct a prudence review of our fuel and purchased power for 2003. We are unable to predict if the OCC will order a prudence review of our fuel and purchased power activities for 2003 or the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
14,771
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
115
 
Fair Value of New Contracts When Entered During the Period (b)
   
-
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
-
 
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
(10,588
)
Total MTM Risk Management Contract Net Assets
   
4,298
 
Net Cash Flow Hedge Contracts (f)
   
(913
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
3,385
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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 Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(f)
“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).




Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Cash Flow Hedges
 
Total (b)
 
Current Assets
 
$
7,540
 
$
908
 
$
8,448
 
Noncurrent Assets
   
6,510
   
70
   
6,580
 
Total MTM Derivative Contract Assets
   
14,050
   
978
   
15,028
 
                     
Current Liabilities
   
(6,692
)
 
(1,716
)
 
(8,408
)
Noncurrent Liabilities
   
(3,060
)
 
(175
)
 
(3,235
)
Total MTM Derivative Contract Liabilities
   
(9,752
)
 
(1,891
)
 
(11,643
)
                     
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
4,298
 
$
(913
)
$
3,385
 

(a)
Does not include Cash Flow Hedges.
(b)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005
(in thousands)

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009
 
Total (c)
 
Prices Actively Quoted - Exchange Traded
  Contracts
 
$
(927
)
$
357
 
$
739
 
$
-
 
$
-
 
$
-
 
$
169
 
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
1,804
   
1,532
   
1,127
   
483
   
-
   
-
   
4,946
 
Prices Based on Models and Other Valuation
  Methods (b)
   
21
   
(1,302
)
 
(1,086
)
 
263
   
580
   
707
   
(817
)
Total
 
$
898
 
$
587
 
$
780
 
$
746
 
$
580
 
$
707
 
$
4,298
 

(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” is in 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.
(c)
Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance December 31, 2004
 
$
1,000
 
$
(600
)
$
400
 
Changes in Fair Value (a)
   
(1,570
)
 
945
   
(625
)
Reclassifications from AOCI to Net
  Income (b)
   
(368
)
 
-
   
(368
)
Ending Balance March 31, 2005
 
$
(938
)
$
345
 
$
(593
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $810 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$61
 
$134
 
$66
 
$40
 
$238
 
$778
 
$335
 
$115
 

VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $40 million and $35 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or financial position.



PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
250,368
 
$
204,043
 
Sales to AEP Affiliates
   
2,632
   
3,142
 
TOTAL
   
253,000
   
207,185
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
134,171
   
89,085
 
Purchased Electricity for Resale
   
14,793
   
9,168
 
Purchased Electricity from AEP Affiliates
   
22,845
   
26,899
 
Other Operation
   
30,185
   
43,395
 
Maintenance
   
11,359
   
13,122
 
Depreciation and Amortization
   
22,619
   
22,176
 
Taxes Other Than Income Taxes
   
9,677
   
9,817
 
Income Taxes (Credits)
   
(852
)
 
(7,333
)
TOTAL
   
244,797
   
206,329
 
               
OPERATING INCOME
   
8,203
   
856
 
               
Nonoperating Income
   
478
   
244
 
Nonoperating Expenses
   
551
   
542
 
Nonoperating Income Tax Credit
   
250
   
392
 
Interest Charges
   
7,875
   
9,953
 
               
NET INCOME (LOSS)
   
505
   
(9,003
)
               
Preferred Stock Dividend Requirements
   
53
   
53
 
               
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK
 
$
452
 
$
(9,056
)

The common stock of PSO is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
157,230
 
$
230,016
 
$
139,604
 
$
(43,842
)
$
483,008
 
                                 
Common Stock Dividends
               
(8,750
)
       
(8,750
)
Preferred Stock Dividends
               
(53
)
       
(53
)
TOTAL
                           
474,205
 
                                 
COMPREHENSIVE LOSS
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $239
                     
(444
)
 
(444
)
NET LOSS
               
(9,003
)
       
(9,003
)
TOTAL COMPREHENSIVE LOSS
                           
(9,447
)
                                 
MARCH 31, 2004
 
$
157,230
 
$
230,016
 
$
121,798
 
$
(44,286
)
$
464,758
 
                                 
DECEMBER 31, 2004
 
$
157,230
 
$
230,016
 
$
141,935
 
$
75
 
$
529,256
 
                                 
Common Stock Dividends
               
(8,500
)
       
(8,500
)
Preferred Stock Dividends
               
(53
)
       
(53
)
TOTAL
                           
520,703
 
                                 
COMPREHENSIVE LOSS
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $534
                     
(993
)
 
(993
)
NET INCOME
               
505
         
505
 
TOTAL COMPREHENSIVE LOSS
                           
(488
)
                                 
MARCH 31, 2005
 
$
157,230
 
$
230,016
 
$
133,887
 
$
(918
)
$
520,215
 

See Notes to Financial Statements of Registrant Subsidiaries.




PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
     
Production
 
$
1,068,205
 
$
1,072,022
 
Transmission
   
467,953
   
468,735
 
Distribution
   
1,100,348
   
1,089,187
 
General
   
201,397
   
200,044
 
Construction Work in Progress
   
47,129
   
41,028
 
Total
   
2,885,032
   
2,871,016
 
Accumulated Depreciation and Amortization
   
1,126,729
   
1,117,113
 
TOTAL - NET
   
1,758,303
   
1,753,903
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
4,636
   
4,401
 
Other Investments
   
-
   
81
 
TOTAL
   
4,636
   
4,482
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
642
   
91
 
Other Cash Deposits
   
156
   
188
 
Accounts Receivable:
             
Customers
   
31,319
   
34,002
 
Affiliated Companies
   
31,288
   
46,399
 
Miscellaneous
   
8,747
   
6,984
 
Allowance for Uncollectible Accounts
   
-
   
(76
)
Fuel Inventory
   
14,674
   
14,268
 
Materials and Supplies
   
37,950
   
35,485
 
Risk Management Assets
   
8,448
   
21,388
 
Regulatory Asset for Under-Recovered Fuel Costs
   
-
   
366
 
Margin Deposits
   
1,388
   
2,881
 
Prepayments and Other
   
2,532
   
1,378
 
TOTAL
   
137,144
   
163,354
 
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
Unamortized Loss on Reacquired Debt
   
14,143
   
14,705
 
Other
   
16,401
   
17,246
 
Long-term Risk Management Assets
   
6,580
   
14,477
 
Prepaid Pension Obligations
   
82,466
   
82,419
 
Deferred Charges and Other Assets
   
39,958
   
18,232
 
TOTAL
   
159,548
   
147,079
 
               
TOTAL ASSETS
 
$
2,059,631
 
$
2,068,818
 

See Notes to Financial Statements of Registrant Subsidiaries.




PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
Common Shareholder’s Equity:
             
Common Stock - $15 par value per share:
             
Authorized - 11,000,000 shares
             
Issued - 10,482,000 shares
             
Outstanding - 9,013,000 shares
 
$
157,230
 
$
157,230
 
Paid-in Capital
   
230,016
   
230,016
 
Retained Earnings
   
133,887
   
141,935
 
Accumulated Other Comprehensive Income (Loss)
   
(918
)
 
75
 
Total Common Shareholder’s Equity
   
520,215
   
529,256
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
5,262
   
5,262
 
Total Shareholders’ Equity
   
525,477
   
534,518
 
Long-term Debt:
             
Nonaffiliated
   
446,121
   
446,092
 
Affiliated
   
50,000
   
50,000
 
Total Long-term Debt
   
496,121
   
496,092
 
TOTAL
   
1,021,598
   
1,030,610
 
CURRENT LIABILITIES
             
Long-term Debt Due Within One Year - Nonaffiliated
   
50,000
   
50,000
 
Advances from Affiliates
   
39,588
   
55,002
 
Accounts Payable:
             
General
   
66,278
   
71,442
 
Affiliated Companies
   
53,755
   
58,632
 
Customer Deposits
   
33,867
   
33,757
 
Taxes Accrued
   
33,817
   
18,835
 
Interest Accrued
   
2,725
   
4,023
 
Risk Management Liabilities
   
8,408
   
13,705
 
Regulatory Liability for Over-Recovered Fuel Costs
   
40,529
   
-
 
Obligations Under Capital Leases
   
603
   
537
 
Other
   
18,449
   
30,477
 
TOTAL
   
348,019
   
336,410
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
386,293
   
384,090
 
Long-term Risk Management Liabilities
   
3,235
   
7,455
 
Regulatory Liabilities:
             
Asset Removal Costs
   
225,316
   
220,298
 
Deferred Investment Tax Credits
   
28,172
   
28,620
 
SFAS 109 Regulatory Liability, Net
   
21,351
   
21,963
 
Unrealized Gain on Forward Commitments
   
7,339
   
19,676
 
Obligations Under Capital Leases
   
1,086
   
747
 
Deferred Credits and Other
   
17,222
   
18,949
 
TOTAL
   
690,014
   
701,798
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
2,059,631
 
$
2,068,818
 

See Notes to Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income (Loss)
 
$
505
 
$
(9,003
)
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
             
Depreciation and Amortization
   
22,619
   
22,176
 
Deferred Property Taxes
   
(24,368
)
 
(25,943
)
Deferred Income Taxes
   
2,126
   
(489
)
Deferred Investment Tax Credits
   
(448
)
 
(448
)
Mark-to-Market of Risk Management Contracts
   
10,473
   
10,029
 
Fuel Recovery
   
40,895
   
4,398
 
Change in Other Noncurrent Assets
   
(4,964
)
 
(1,664
)
Change in Other Noncurrent Liabilities
   
(9,279
)
 
(7,768
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
15,955
   
4,054
 
Fuel, Materials and Supplies
   
(2,871
)
 
635
 
Accounts Payable
   
(10,041
)
 
(7,740
)
Taxes Accrued
   
14,982
   
17,424
 
Customer Deposits
   
110
   
2,357
 
Interest Accrued
   
(1,298
)
 
32
 
Other Current Assets
   
2,285
   
(576
)
Other Current Liabilities
   
(11,964
)
 
(4,562
)
Net Cash Flows From Operating Activities
   
44,717
   
2,912
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(20,231
)
 
(14,471
)
Change in Other Cash Deposits, Net
   
32
   
3,688
 
Proceeds from Sale of Assets
   
-
   
244
 
Net Cash Flows Used For Investing Activities
   
(20,199
)
 
(10,539
)
               
FINANCING ACTIVITIES
             
Changes in Advances to/from Affiliates, Net
   
(15,414
)
 
14,778
 
Dividends Paid on Common Stock
   
(8,500
)
 
(8,750
)
Dividends Paid on Cumulative Preferred Stock
   
(53
)
 
(53
)
Net Cash Flows From (Used For) Financing Activities
   
(23,967
)
 
5,975
 
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
551
   
(1,652
)
Cash and Cash Equivalents at Beginning of Period
   
91
   
3,738
 
Cash and Cash Equivalents at End of Period
 
$
642
 
$
2,086
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $7,806,000 and $8,951,000 and for income taxes was $(1,366,000) and $(2,695,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $551,000 and $141,000 in 2005 and 2004, respectively.

See Notes to Respective Financial Statements.



PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to PSO’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to PSO.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments and Contingencies
Note 5
Guarantees
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Financing Activities
Note 10

 
 
 
 
 
 
 
 
 
 
 
 



 
 
 
 
 
 
 
 
 
 
 
 

 

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
 
 
 
 
 
 
 
 
 
 
 

 






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2005 Compared to First Quarter of 2004

Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)

First Quarter of 2004 Net Income
       
$
5
 
               
Changes in Gross Margin:
             
Retail Margins*
   
3
       
Off-system Sales
   
(1
)
     
Other Revenues
   
1
       
Total Change in Gross Margin
         
3
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
5
       
Depreciation and Amortization
   
(1
)
     
Taxes Other Than Income Taxes
   
1
       
Interest Charges
   
3
       
Total Change in Operating Expenses and Other:
         
8
 
               
Income Tax Expense
         
(4
)
               
First Quarter of 2005 Net Income
       
$
12
 

*
Includes firm wholesale sales to municipals and cooperatives.

Net Income increased $7 million to $12 million in the first quarter of 2005. The key drivers of the increase were a $3 million increase in gross margin and an $8 million net decrease in operating expenses and other partially offset by a $4 million increase in income taxes.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

·
Retail Margins increased $3 million in comparison to 2004 primarily due to a $1 million increase in retail sales due to slightly higher volumes and a $2 million increase in net fuel revenue/fuel expense.
·
Margins from Off-system Sales decreased $1 million in comparison to 2004 primarily due to lower optimization activity.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $5 million. Transmission related expenses decreased $6 million primarily due to a prior year unfavorable adjustment for affiliated OATT and ancillary services resulting from revised ERCOT data for the years 2001 through 2003, offset in part by $1 million of higher production plant related expenses.
·
Taxes Other Than Income Taxes decreased $1 million primarily due to property related taxes and state franchise taxes.
·
Interest Charges decreased $3 million primarily due to refinancing higher interest rate debt with lower interest rate debt.
 
Income Taxes

The effective tax rates for the first quarter of 2005 and 2004 were 26.5% and (4.7%), respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is primarily due to higher pretax income in 2005 and federal income tax adjustments.

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
 
A-
 
A
Senior Unsecured Debt
Baa1
 
BBB
 
A-

Cash Flow

Cash flows for the three months ended March 31, 2005 and 2004 were as follows:

   
2005
 
2004
 
   
(in thousands)
 
Cash and cash equivalents at beginning of period
 
$
2,308
 
$
5,676
 
Cash flows from (used for):
             
Operating activities
   
53,866
   
16,892
 
Investing activities
   
(33,260
)
 
(72,298
)
Financing activities
   
(15,941
)
 
56,959
 
Net increase in cash and cash equivalents
   
4,665
   
1,553
 
Cash and cash equivalents at end of period
 
$
6,973
 
$
7,229
 

Operating Activities

Our net cash flows from operating activities were $54 million in 2005. We produced income of $12 million during the period and noncash expense items of $32 million for Depreciation and Amortization and $(29) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items; the most significant are Accounts Receivable, Net, Fuel, Materials and Supplies, Accounts Payable and Taxes Accrued. Accounts Receivable, Net decreased $13 million related to decreased affiliated energy transactions. The $2 million decrease in Fuel, Materials and Supplies is primarily due to lower purchases of fuel. Accounts Payable decreased $6 million due primarily to lower vendor related payables and lower affiliated energy transactions. Taxes Accrued increased $16 million primarily due to the annual tax accruals related to 2005 property taxes offset in part by a reduction of income tax related accruals.

Our net cash flows from operating activities were $17 million in 2004. We produced income of $5 million during the period and noncash expense items of $31 million for Depreciation and Amortization and $(29) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items; the most significant are Accounts Receivable, Net, Fuel, Materials and Supplies, Accounts Payable and Taxes Accrued. Accounts Receivables, Net increased $13 million related to affiliated energy transactions. The $6 million decrease in Fuel, Materials and Supplies is primarily due to lower purchases of fuel. Accounts Payable decreased $14 million primarily due to lower vendor related payables and lower affiliated energy transactions. Taxes Accrued increased $40 million primarily due to the annual tax accruals related to 2004 property taxes and by an increase of income tax related accruals.

Investing Activities

Cash flows used for investing activities during 2005 and 2004 were $33 million and $72 million, respectively. They were comprised of Construction Expenditures related to projects for improved transmission and distribution service reliability and in 2004, a Change in Other Cash Deposits, Net related to funds held in trust for the retirement of Installment Purchase Contracts. For the remainder of 2005, we expect our Construction Expenditures to be approximately $170 million.

Financing Activities

Cash flows from financing activities were $16 million during 2005. During the first quarter, we retired $2 million of Notes Payable. Common stock dividends were $13 million.

Cash flows from financing activities were $57 million during 2004. During the first quarter, we increased our Utility Money Pool borrowing by $103 million, retired $83 million of First Mortgage Bonds, issued $52 million of Installment Purchase Contracts and paid $15 million in common stock dividends.

Financing Activity

There were no long-term debt issuances during the first three months of 2005. Retirements are shown below:

Retirements

   
Principal
 
Interest
 
Due
Type of Debt
 
Amount
 
Rate
 
Date
   
(in thousands)
 
(%)
   
             
Note Payable
 
$1,707
 
4.47
 
2011
Note Payable
 
     750
 
Variable
 
2008

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section  for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

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.

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004
 
$
17,527
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(2,871
)
Fair Value of New Contracts When Entered During the Period (b)
   
21
 
Net Option Premiums Paid/(Received) (c)
   
-
 
Change in Fair Value Due to Valuation Methodology Changes
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
(1,448
)
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)
   
(8,121
)
Total MTM Risk Management Contract Net Assets
   
5,108
 
Net Cash Flow Hedge Contracts (f)
   
(4,095
)
Total MTM Risk Management Contract Net Assets at March 31, 2005
 
$
1,013
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(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 in 2005.
(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)
“Changes 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.
(f)
“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

 
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)

   
MTM Risk Management Contracts (a)
 
Cash Flow Hedges
 
Total (b)
 
Current Assets
 
$
9,003
 
$
449
 
$
9,452
 
Noncurrent Assets
   
7,756
   
82
   
7,838
 
Total MTM Derivative Contract Assets
   
16,759
   
531
   
17,290
 
                     
Current Liabilities
   
(7,996
)
 
(4,142
)
 
(12,138
)
Noncurrent Liabilities
   
(3,655
)
 
(484
)
 
(4,139
)
Total MTM Derivative Contract Liabilities
   
(11,651
)
 
(4,626
)
 
(16,277
)
                     
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
5,108
 
$
(4,095
)
$
1,013
 

(a)
Does not include Cash Flow Hedges.
(b)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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:

·
The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
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 March 31, 2005

   
Remainder of 2005
 
2006
 
2007
 
2008
 
2009
 
After
2009
 
Total (c)
 
Prices Actively Quoted - Exchange Traded
  Contracts
 
$
(1,102
)
$
424
 
$
878
 
$
-
 
$
-
 
$
-
 
$
200
 
Prices Provided by Other External Sources -  
  OTC Broker Quotes (a)
   
2,145
   
1,821
   
1,339
   
574
   
-
   
-
   
5,879
 
Prices Based on Models and Other Valuation
  Methods (b)
   
24
   
(1,547
)
 
(1,291
)
 
313
   
690
   
840
   
(971
)
Total
 
$
1,067
 
$
698
 
$
926
 
$
887
 
$
690
 
$
840
 
$
5,108
 

(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” is in 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.
(c)
Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance December 31, 2004
 
$
1,188
 
$
(2,008
)
$
(820
)
Changes in Fair Value (a)
   
(1,867
)
 
774
   
(1,093
)
Reclassifications from AOCI to Net Income (b)
   
(436
)
 
-
   
(436
)
Ending Balance March 31, 2005
 
$
(1,115
)
$
(1,234
)
$
(2,349
)

(a)
“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes.
(b)
“Reclassifications from AOCI 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 AOCI expected to be reclassified to earnings during the next twelve months is a $1,123 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.
 
VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:

 
Three Months Ended
 
Twelve Months Ended
 
 
March 31, 2005
 
December 31, 2004
 
 
(in thousands)
 
(in thousands)
 
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
 
$72
 
$159
 
$78
 
$47
 
$283
 
$923
 
$398
 
$136
 

VaR Associated with Debt Outstanding

The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $32 million and $31 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING REVENUES
         
Electric Generation, Transmission and Distribution
 
$
229,874
 
$
213,949
 
Sales to AEP Affiliates
   
17,122
   
22,211
 
TOTAL
   
246,996
   
236,160
 
               
OPERATING EXPENSES
             
Fuel for Electric Generation
   
90,110
   
88,823
 
Purchased Electricity for Resale
   
13,380
   
5,934
 
Purchased Electricity from AEP Affiliates
   
5,864
   
7,307
 
Other Operation
   
44,449
   
50,268
 
Maintenance
   
15,715
   
15,648
 
Depreciation and Amortization
   
32,393
   
31,285
 
Taxes Other Than Income Taxes
   
15,663
   
16,567
 
Income Taxes
   
4,596
   
131
 
TOTAL
   
222,170
   
215,963
 
               
OPERATING INCOME
   
24,826
   
20,197
 
               
Nonoperating Income
   
1,319
   
1,403
 
Nonoperating Expenses
   
474
   
611
 
Nonoperating Income Tax Credit
   
200
   
356
 
Interest Charges
   
12,780
   
15,443
 
Minority Interest
   
(886
)
 
(881
)
               
NET INCOME
   
12,205
   
5,021
 
               
Preferred Stock Dividend Requirements
   
57
   
57
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
12,148
 
$
4,964
 

The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.
 
 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2003
 
$
135,660
 
$
245,003
 
$
359,907
 
$
(43,910
)
$
696,660
 
                                 
Common Stock Dividends
               
(15,000
)
       
(15,000
)
Preferred Stock Dividends
               
(57
)
       
(57
)
TOTAL
                           
681,603
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income (Loss), Net  of Taxes:
                               
Cash Flow Hedges, Net of Tax of $281
                     
(522
)
 
(522
)
Minimum Pension Liability, Net of Tax of  $12,420
                     
23,066
   
23,066
 
NET INCOME
               
5,021
         
5,021
 
TOTAL COMPREHENSIVE INCOME
                           
27,565
 
                                 
MARCH 31, 2004
 
$
135,660
 
$
245,003
 
$
349,871
 
$
(21,366
)
$
709,168
 
                                 
DECEMBER 31, 2004
 
$
135,660
 
$
245,003
 
$
389,135
 
$
(1,180
)
$
768,618
 
                                 
Common Stock Dividends
               
(12,500
)
       
(12,500
)
Preferred Stock Dividends
               
(57
)
       
(57
)
TOTAL
                           
756,061
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $824
                     
(1,529
)
 
(1,529
)
NET INCOME
               
12,205
         
12,205
 
TOTAL COMPREHENSIVE INCOME
                           
10,676
 
                                 
MARCH 31, 2005
 
$
135,660
 
$
245,003
 
$
388,783
 
$
(2,709
)
$
766,737
 

See Notes to Financial Statements of Registrant Subsidiaries.
 



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
ELECTRIC UTILITY PLANT
     
Production
 
$
1,668,689
 
$
1,663,161
 
Transmission
   
634,206
   
632,964
 
Distribution
   
1,121,224
   
1,114,480
 
General
   
428,751
   
427,910
 
Construction Work in Progress
   
59,465
   
48,852
 
Total
   
3,912,335
   
3,887,367
 
Accumulated Depreciation and Amortization
   
1,734,533
   
1,709,758
 
TOTAL - NET
   
2,177,802
   
2,177,609
 
               
OTHER PROPERTY AND INVESTMENTS
             
Nonutility Property, Net
   
4,049
   
4,049
 
Other Investments
   
4,628
   
4,628
 
TOTAL
   
8,677
   
8,677
 
               
CURRENT ASSETS
             
Cash and Cash Equivalents
   
6,973
   
2,308
 
Other Cash Deposits
   
6,504
   
6,292
 
Advances to Affiliates
   
40,033
   
39,106
 
Accounts Receivable:
             
Customers
   
40,117
   
39,042
 
Affiliated Companies
   
14,733
   
28,817
 
Miscellaneous
   
5,834
   
5,856
 
Allowance for Uncollectible Accounts
   
(5
)
 
(45
)
Fuel Inventory
   
42,531
   
45,793
 
Materials and Supplies
   
36,886
   
36,051
 
Risk Management Assets
   
9,452
   
25,379
 
Regulatory Asset for Under-Recovered Fuel Costs
   
-
   
4,687
 
Margin Deposits
   
1,650
   
3,419
 
Prepayments and Other
   
17,639
   
18,331
 
TOTAL
   
222,347
   
255,036
 
               
               
DEFERRED DEBITS AND OTHER ASSETS
             
Regulatory Assets:
             
SFAS 109 Regulatory Asset, Net
   
20,874
   
18,000
 
Unamortized Loss on Reacquired Debt
   
20,067
   
20,765
 
Other
   
14,100
   
16,350
 
Long-term Risk Management Assets
   
7,838
   
17,179
 
Prepaid Pension Obligations
   
80,941
   
81,132
 
Deferred Charges
   
74,217
   
51,561
 
TOTAL
   
218,037
   
204,987
 
               
TOTAL ASSETS
 
$
2,626,863
 
$
2,646,309
 

See Notes to Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)

   
2005
 
2004
 
CAPITALIZATION
 
(in thousands)
 
Common Shareholder’s Equity:
             
Common Stock - $18 par value per share:
             
Authorized - 7,600,000 shares
             
Outstanding - 7,536,640 shares
 
$
135,660
 
$
135,660
 
Paid-in Capital
   
245,003
   
245,003
 
Retained Earnings
   
388,783
   
389,135
 
Accumulated Other Comprehensive Income (Loss)
   
(2,709
)
 
(1,180
)
Total Common Shareholder’s Equity
   
766,737
   
768,618
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
4,700
   
4,700
 
Total Shareholders’ Equity
   
771,437
   
773,318
 
Long-term Debt:
             
Nonaffiliated
   
535,525
   
545,395
 
Affiliated
   
50,000
   
50,000
 
Total Long-term Debt
   
585,525
   
595,395
 
TOTAL
   
1,356,962
   
1,368,713
 
               
Minority Interest
   
1,921
   
1,125
 
               
CURRENT LIABILITIES
             
Long-term Debt Due Within One Year - Nonaffiliated
   
217,474
   
209,974
 
Accounts Payable:
             
General
   
36,154
   
40,001
 
Affiliated Companies
   
30,719
   
33,285
 
Customer Deposits
   
29,684
   
30,550
 
Taxes Accrued
   
61,590
   
45,474
 
Interest Accrued
   
11,523
   
12,509
 
Risk Management Liabilities
   
12,138
   
18,607
 
Obligations Under Capital Leases
   
4,052
   
3,692
 
Regulatory Liability for Over-Recovered Fuel Costs
   
13,655
   
9,891
 
Other
   
32,083
   
33,417
 
TOTAL
   
449,072
   
437,400
 
               
DEFERRED CREDITS AND OTHER LIABILITIES
             
Deferred Income Taxes
   
397,563
   
399,756
 
Long-term Risk Management Liabilities
   
4,139
   
9,128
 
Reclamation Reserve
   
5,761
   
7,624
 
Regulatory Liabilities:
             
Asset Removal Costs
   
250,637
   
249,892
 
Deferred Investment Tax Credits
   
34,466
   
35,539
 
Excess Earnings
   
3,167
   
3,167
 
Other
   
11,104
   
21,320
 
Asset Retirement Obligations
   
27,518
   
27,361
 
Obligations Under Capital Leases
   
30,525
   
30,854
 
Deferred Credits and Other
   
54,028
   
54,430
 
TOTAL
   
818,908
   
839,071
 
               
Commitments and Contingencies (Note 5)
             
               
TOTAL CAPITALIZATION AND LIABILITIES
 
$
2,626,863
 
$
2,646,309
 

See Notes to Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)

   
2005
 
2004
 
OPERATING ACTIVITIES
           
Net Income
 
$
12,205
 
$
5,021
 
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
             
Depreciation and Amortization
   
32,393
   
31,285
 
Deferred Property Taxes
   
(28,570
)
 
(29,063
)
Deferred Income Taxes
   
(4,312
)
 
(5,182
)
Deferred Investment Tax Credits
   
(1,073
)
 
(1,081
)
Mark-to-Market of Risk Management Contracts
   
12,419
   
11,837
 
Over/Under Fuel Recovery
   
8,451
   
9,649
 
Change in Other Noncurrent Assets
   
4,760
   
1,175
 
Change in Other Noncurrent Liabilities
   
(10,413
)
 
(3,620
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
12,991
   
(12,895
)
Fuel, Materials and Supplies
   
2,427
   
6,226
 
Accounts Payable
   
(6,413
)
 
(13,590
)
Taxes Accrued
   
16,116
   
39,682
 
Customer Deposits
   
(866
)
 
2,132
 
Interest Accrued
   
(986
)
 
(2,598
)
Other Current Assets
   
4,849
   
901
 
Other Current Liabilities
   
(112
)
 
(22,987
)
Net Cash Flows From Operating Activities
   
53,866
   
16,892
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(33,156
)
 
(19,376
)
Change in Other Cash Deposits, Net
   
(212
)
 
(52,922
)
Proceeds from Sale of Assets
   
108
   
-
 
Net Cash Flows Used For Investing Activities
   
(33,260
)
 
(72,298
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt
   
-
   
52,179
 
Retirement of Long-term Debt
   
(2,457
)
 
(82,907
)
Changes in Advances to/from Affiliates, Net
   
(927
)
 
102,744
 
Dividends Paid on Common Stock
   
(12,500
)
 
(15,000
)
Dividends Paid on Cumulative Preferred Stock
   
(57
)
 
(57
)
Net Cash Flows From (Used For) Financing Activities
   
(15,941
)
 
56,959
 
               
Net Increase in Cash and Cash Equivalents
   
4,665
   
1,553
 
Cash and Cash Equivalents at Beginning of Period
   
2,308
   
5,676
 
Cash and Cash Equivalents at End of Period
 
$
6,973
 
$
7,229
 

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $12,304,000 and $15,964,000 and for income taxes was $22,257,000 and $(2,228,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $775,000 and $887,000 in 2005 and 2004, respectively.

See Notes to Respective Financial Statements.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to SWEPCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to SWEPCo.

 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments and Contingencies
Note 5
Guarantees
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Financing Activities
Note 10

 


NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to financial statements that follow are a combined presentation for AEP’s registrant subsidiaries. The following list indicates the registrants to which the footnotes apply:
     
 1.
Significant Accounting Matters
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
 2.
New Accounting Pronouncements
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
 3.
Rate Matters
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
 4.
Customer Choice and Industry Restructuring
CSPCo, OPCo, TCC, TNC
 5.
Commitments and Contingencies
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
 6.
Guarantees
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
 7.
Dispositions and Assets Held for Sale
TCC
 8.
Benefit Plans
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
 9.
Business Segments
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10.
Financing Activities
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC



1. SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited interim financial statements should be read in conjunction with the 2004 Annual Report as incorporated in and filed with our 2004 Form 10-K.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods.

Components of Accumulated Other Comprehensive Income (Loss) 

Accumulated Other Comprehensive Income (Loss) is included on the balance sheet in the capitalization section. The components of Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries are shown in the following table:

   
March 31,
 
December 31,
 
   
2005
 
2004
 
   
(in thousands)
 
Components
           
Cash Flow Hedges:
           
APCo
 
$
(17,034
)
$
(9,324
)
CSPCo
   
(4,381
)
 
1,393
 
I&M
   
(10,389
)
 
(4,076
)
KPCo
   
(1,814
)
 
813
 
OPCo
   
(6,695
)
 
1,241
 
PSO
   
(593
)
 
400
 
SWEPCo
   
(2,349
)
 
(820
)
TCC
   
(3,679
)
 
657
 
TNC
   
(489
)
 
285
 
               
Minimum Pension Liability:
             
APCo
 
$
(72,348
)
$
(72,348
)
CSPCo
   
(62,209
)
 
(62,209
)
I&M
   
(41,175
)
 
(41,175
)
KPCo
   
(9,588
)
 
(9,588
)
OPCo
   
(75,505
)
 
(75,505
)
PSO
   
(325
)
 
(325
)
SWEPCo
   
(360
)
 
(360
)
TCC
   
(4,816
)
 
(4,816
)
TNC
   
(413
)
 
(413
)

Accounting for Asset Retirement Obligations

All of AEP’s Registrant Subsidiaries 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.

The following is a reconciliation of beginning and ending aggregate carrying amounts of asset retirement obligations by Registrant Subsidiary:

   
Balance at January 1, 2005
 
Accretion
 
Liabilities Incurred
 
Liabilities Settled
 
Revisions in Cash Flow Estimates
 
Balance at March 31, 2005
 
   
(in millions)
 
AEGCo (a)
 
$
1.2
 
$
-
 
$
-
 
$
-
 
$
-
 
$
1.2
 
APCo (a)
   
24.6
   
0.5
   
-
   
-
   
-
   
25.1
 
CSPCo (a)
   
11.6
   
0.2
   
-
   
-
   
-
   
11.8
 
I&M (b)
   
711.8
   
11.6
   
-
   
-
   
-
   
723.4
 
OPCo (a)
   
45.6
   
0.9
   
-
   
-
   
-
   
46.5
 
SWEPCo (c)
   
27.4
   
0.2
   
-
   
(0.1
)
 
-
   
27.5
 
TCC (d)
   
248.9
   
4.5
   
-
   
-
   
-
   
253.4
 

(a)
Consists of asset retirement obligations related to ash ponds.
(b)
Consists of asset retirement obligations related to ash ponds ($1.2 million at March 31, 2005) and nuclear decommissioning costs for the Cook Plant ($722.2 million at March 31, 2005).
(c)
Consists of asset retirement obligations related to Sabine Mining Company and Dolet Hills Lignite Company, LLC.
(d)
Consists of asset retirement obligations related to nuclear decommissioning costs for STP included in Liabilities Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.

Accretion expense is included in Other Operation expense in the respective income statements of the individual registrant subsidiaries.

As of March 31, 2005 and December 31 2004, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $962 million ($819 million for I&M and $143 million for TCC) and $934 million ($791 million for I&M and $143 million for TCC), respectively, recorded in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds on I&M’s Consolidated Balance Sheets and in Assets Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.

Reclassification 

Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income (Loss).

Prior Period Adjustment

As disclosed in the 2004 Annual Report, in the second quarter of 2004 the Registrant Subsidiaries implemented FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003 (FSP FAS 106-2), retroactive to January 1, 2004. The effect of implementing FSP FAS 106-2 on the first quarter of 2004 is as follows:


   
Originally Reported Net Income (Loss)
 
Effect of Medicare Subsidy
 
Restated Net Income (Loss)
 
   
(in thousands)
 
APCo
 
$
64,521
 
$
815
 
$
65,336
 
CSPCo
   
44,705
   
414
   
45,119
 
I&M
   
42,376
   
632
   
43,008
 
KPCo
   
11,490
   
121
   
11,611
 
OPCo
   
79,444
   
720
   
80,164
 
PSO
   
(9,284
)
 
281
   
(9,003
)
SWEPCo
   
4,730
   
291
   
5,021
 
TCC
   
29,077
   
327
   
29,404
 
TNC
   
12,953
   
143
   
13,096
 


2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented during 2005 that we have determined relate to our operations.

SFAS 123 (revised 2004) “Share-Based Payment” (SFAS 123R)

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting previously available under Accounting Principles Board (APB) Opinion No. 25. The statement is effective as of the first annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement.

We will implement SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost will be based on the grant-date fair value of the equity award. The Registrant Subsidiaries do not expect implementation of SFAS 123R to materially affect their results of operations, cash flows or financial condition.

In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47)

In March 2005, the FASB issued FIN 47, which interprets the application of SFAS 143. FIN 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Entities are required to record a liability for the fair value of a conditional asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

The Registrant Subsidiaries will implement FIN 47 during the fourth quarter of 2005. Implementation will require an adjustment for the cumulative effect for the nonregulated operations of initially applying FIN 47 to be recorded as a change in accounting principle, disclosure of pro forma liabilities and asset retirement obligations, and other additional disclosures. The Registrant Subsidiaries have not completed their evaluation of any potential impact to their results of operations, cash flows or financial condition.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and 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. The FASB is currently working on several projects including business combinations, operating segments, liabilities and equity, revenue recognition, pension plans, fair value measurements, accounting changes and related tax impacts. We also expect to see more FASB projects as a result of their desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position.


3. RATE MATTERS

As discussed in our 2004 Annual Report, rate and regulatory proceedings at the FERC and at several state commissions are ongoing. The Rate Matters note within our 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending. The following sections discuss current activities and update the 2004 Annual Report.

Louisiana Fuel Audit - Affecting SWEPCo

The Louisiana Public Service Commission (LPSC) is performing an audit of SWEPCo’s historical fuel costs and addressing customer complaints regarding potential overcharge of fuel costs. In testimony filed in this matter, the LPSC Staff recommended refunds of approximately $5 million. In subsequent surrebuttal testimony filed by the LPSC Staff, they recognized that SWEPCo’s costs were reasonable but that certain costs would be more appropriately recovered through base rates. While initial indications from the LPSC Staff surrebuttal testimony would not indicate a material disallowance, management cannot predict the ultimate outcome in this proceeding. If the LPSC or the Court does not agree with LPSC Staff recommendations, it could have an adverse effect on SWEPCo’s future results of operations and cash flows.

PSO Fuel and Purchased Power - Affecting PSO

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices.

In the proceeding, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and AEP West companies should have received more margins. The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. Using the intervenors’ method, PSO estimates that the increase in margins would be $29 million through March 31, 2005. In April 2005, the OCC heard arguments from intervenors that requested the OCC to conduct a prudence review of PSO’s fuel and purchased power for 2003. Management is unable to predict if the OCC will order a prudence review of PSO’s fuel and purchased power activities for 2003 or the ultimate effect of these proceedings on PSO’s revenues, results of operations, cash flows and financial condition.

Michigan Fuel Recovery Plan - Affecting I&M

In September 2004, I&M filed its 2005 Power Supply Cost Recovery (PSCR) Plan, with the requested PSCR factors implemented pursuant to the statute effective with January 2005 billings, replacing the 2004 factors. On March 29, 2005, the Michigan Public Service Commission (MPSC) issued an order approving a settlement agreement authorizing the proposed 2005 PSCR Plan factors.

On March 31, 2005, I&M filed its 2004 PSCR Reconciliation seeking recovery of approximately $2 million of unrecovered PSCR fuel costs and interest proposed to be recovered through the application of customer bill surcharges during October 2005 through December 2005.

On April 28, 2005, the MPSC issued an Opinion and Order approving I&M’s proposed 2004 PSCR factors as billed and finding in favor of I&M on all issues, including the proposed treatment of net SO2 and NOx credits.

TCC Rate Case - Affecting TCC

TCC has an on-going transmission and distribution (T&D) rate review before the PUCT. In that rate review, the PUCT has issued various decisions and conducted additional hearings in March 2005. At an open meeting on April 13, 2005, the PUCT decided all remaining issues except the amount of affiliate expenses to include in revenue requirements, which the PUCT decided to defer. Adjusted for the decisions approved by the PUCT through April 13, 2005, the ALJs recommended disallowances of affiliate expenses would produce an annual rate reduction of $25 million to $52 million. If TCC were to prevail on the affiliate expenses issue, the result would be an annual rate increase of $2 million. An order reducing TCC’s rates could have an adverse effect on TCC’s future results of operations and cash flows.

TCC Unbundled Cost of Service (UCOS) Appeal - Affecting TCC

The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began. TCC placed new T&D rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. Certain PUCT rulings, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the 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 nonbypassable T&D rates charged to REPs, discriminates against residential and small commercial customers and is unlawful. Management estimates that the adverse effect of a decision to reduce the PTB rates for the period prior to the sale of the AEP REPs is approximately $11 million pretax. The District Court decision was appealed to the Third Court of Appeals by TCC and other parties. Based on advice of counsel, management believes that it will ultimately prevail on appeal. If the District Court’s decision is ultimately upheld on appeal or the Court of Appeals reverses the District Court on issues adverse to TCC, it could have an adverse effect on TCC’s future results of operations and cash flows.

TCC and TNC ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC

Several parties including the Office of Public Utility Counsel 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. In June 2003, the Court ruled that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The amount of unaccounted for energy built into the PTB fuel factors was approximately $3 million for Mutual Energy WTU. The Court upheld the initial PTB orders on all other issues. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. Management believes, based on the advice of counsel, that the PUCT’s original decision will ultimately be upheld. If the court’s decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in the years 2002 through 2004 resulting in an adverse effect on TCC’s and TNC’s future results of operations and cash flows.

PSO Rate Review - Affecting PSO

PSO is involved in a commission staff-initiated rate review before the OCC seeking to increase its base rates, while various other parties made recommendations to reduce PSO’s base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. Pending approval by the OCC, the settlement provides for a $7 million base rate reduction partially offset by a $6 million reduction in annual depreciation expense. The settlement also provides for recovery of $9 million of deferred fuel and the continuation of the vegetation management rider. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC did not approve the settlement in time for implementation of new base rates in May 2005 as agreed to by the parties, which voids the settlement. The OCC issued an Order approving the stipulation on May 2, 2005 with one exception. The Order approves the implementation of new base rates in June 2005 versus the stipulation date of May 2005.

Indiana Settlement Agreement - Affecting I&M

In 2004, the IURC ordered the continuation of the fixed fuel adjustment charge on an interim basis through March 2005, pending the outcome of negotiations. Certain of the parties to the negotiations reached a settlement and signed an agreement on March 10, 2005, and filed the agreement with the IURC on March 14, 2005. The IURC may rule on the agreement during the second quarter of 2005.

The filed settlement freezes fuel rates for the March 2004 through June 2007 billing months at an increasing rate that includes 8.609 mills per KWH reflected in base rates. The settlement provides that the total fuel rates will be 9.88 mills per KWH from January 2005 through December 2005, 10.26 mills per KWH from January 2006 through December 2006, and 10.63 mills per for KWH from January 2007 through June 2007. Pursuant to a separate IURC order, I&M began billing the 9.88 mills per KWH total fuel rate on an interim basis effective with the April 2005 billing month.

The settlement agreement also covers certain events at the Cook Plant. The settlement provides that if an outage greater than 60 days occurs at Cook Plant, the recovery of actual monthly fuel costs will be in effect for the outage period beyond 60 days, capped by the average AEP System Pool Primary Energy Rate (Primary Energy Rate), excluding I&M, as defined by the AEP System Interconnection Agreement and adjusted for losses. If a second outage greater than 60 days occurs, actual monthly fuel costs capped at the Primary Energy Rate would be recovered through June 2007. Over the term of the settlement, if total actual fuel costs (except during a Cook Plant outage greater than 60 days) are under the cap prices, the excess will be credited to customers over the next two fuel adjustment clause filings. Under the settlement fuel costs in excess of the cap price cannot be recovered. If Cook Plant operates at a capacity factor greater than 87% during the fuel rate freeze period, I&M will receive credit for 30% of the savings produced and customers will be credited with 70% of these savings over the first two fuel filings after the fuel rate freeze period ends in June 2007.

Pending approval of the IURC, this settlement agreement also freezes base rates from January 1, 2005 to June 30, 2007 at the rates in effect as of January 1, 2005. During this freeze period, I&M may not implement a general increase in base rates or implement a rider or cost deferral not established in the settlement agreement unless the IURC determines that a significant change in conditions beyond I&M’s control occurs or a material impact on I&M occurs as a result of federal, state or local regulation or statute that mandates reliability standards related to transmission or distribution costs.

If the settlement is approved by the IURC, fuel costs previously expensed since January 2005 exceeding the previously authorized level of 9.2 mills up to 9.88 mills (approximately $4 million through March 31, 2005) would be deferred for future recovery. If future fuel cost per KWH exceeds the caps, or if the base rate freeze precludes I&M from seeking timely rate increases to recover increases in I&M’s cost of service, I&M’s future results of operations and cash flows would be adversely affected.

RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo, and OPCo

Prior to joining PJM, the AEP East companies deferred costs incurred under FERC orders to originally form a new RTO, (the Alliance) and subsequently to join an existing RTO (PJM). In 2004, we requested permission to amortize, beginning January 1, 2005, the $18 million of deferred non-PJM billed formation/integration costs over 15 years and the $17 million of deferred PJM-billed integration costs, but we did not propose an amortization period for the PJM-billed costs in the application. The FERC approved our application.

In January 2005, the AEP East companies began amortizing their deferred non-PJM billed costs over 15 years and the deferred PJM-billed integration costs over 10 years. The total amortization related to such costs was $1 million in the first quarter of 2005. As of March 31, 2005, the AEP East Companies have $34 million of deferred unamortized RTO formation/integration costs.

Company
 
(in millions)
 
APCo
 
$
9.7
 
CSPCo
   
4.0
 
I&M
   
7.4
 
KPCo
   
2.2
 
OPCo
   
11.0
 

On March 8, 2005, we jointly filed with other utilities a request with the FERC to recover deferred PJM-billed integration costs of $17 million from all load-serving entities in the PJM RTO over a ten-year period starting January 1, 2005. On March 31, 2005, we also filed a request for a revised network integration transmission service revenue requirement for the AEP zone of PJM. Included in the costs reflected in that revenue requirement was the budgeted 2005 amortization of our deferred non-PJM billed Alliance RTO formation and PJM integration costs. The AEP East companies will be responsible for paying most of the amounts allocated by the FERC to the AEP East zone since the costs are attributable to their internal load.

Although several parties have filed protests of the joint filing to recover the deferred PJM-billed integration costs, we believe that it is probable that the FERC will ultimately approve recovery of the PJM-billed integration costs through the PJM OATT and that the FERC will grant a long enough amortization period to allow us to recover the deferred non-PJM billed Alliance RTO formation and PJM integration costs in the AEP East retail jurisdictions. If the FERC issues an adverse ruling, the AEP East companies’ future results of operations and cash flows could be adversely affected.

FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo and OPCo

A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. Billing statements from PJM for the first quarter of 2005 did not reflect any credits to AEP for SECA revenues. SECA billings by PJM crediting AEP for its SECA revenue are scheduled to begin in May 2005 with retroactive adjustments to be billed by PJM in June and July 2005. Based upon the SECA transition rate methodology approved by the FERC, the AEP East companies accrued $26 million of SECA revenue in the first quarter of 2005 and has a receivable for SECA revenues of $37 million at March 31, 2005.

   
SECA Revenue for Three
Months Ended
March 31, 2005
 
SECA
Receivable at March 31, 2005
 
Company
 
(in millions)
 
(in millions)
 
APCo
 
$
8.6
 
$
12.1
 
CSPCo
   
4.4
   
6.4
 
I&M
   
4.9
   
7.1
 
KPCo
   
2.0
   
2.8
 
OPCo
   
6.1
   
8.9
 

In a March 2005 FERC filing, we proposed an increase in the rate for network integration transmission service, as well as rates for other ancillary services. The primary customers of these services are the municipal and cooperative wholesale entities that have load delivery points in the AEP zone of PJM. As proposed, the rates will automatically increase to reflect the loss of SECA transition rates on April 1, 2006.

The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate was eliminated and replaced by SECA transition rates was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be sufficient to replace the SECA transition rate revenues and whether the new rates will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, if AEP zonal rates are not sufficiently increased by the FERC after March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.
 
Hold Harmless Proceeding - Affecting AEP East companies

In a July 2002 order conditionally accepting AEP East companies’ choice to join PJM, the FERC directed ComEd, MISO, PJM and us to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from ComEd and us joining PJM instead of MISO.

In July 2004, AEP East companies and PJM filed jointly with the FERC a hold-harmless proposal. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. A hearing is scheduled for May 2005.

The Michigan and Wisconsin utilities have presented studies that show estimated adverse effects to utilities in the two states in the range of $60 million to $70 million over the term of the agreement for AEP East companies and ComEd. The recent supplemental filing by the Michigan companies shows estimated adverse effects to utilities in Michigan of up to $50 million over the term of agreement. AEP East companies and ComEd have presented studies that show no adverse effects to the Michigan and Wisconsin utilities. ComEd has separately settled this issue with the Michigan and Wisconsin utilities for a one time total payment of approximately $5 million, which was approved by the FERC. On December 27, 2004, AEP East companies and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250,000 that was approved by the FERC on March 7, 2005. On April 25, 2005, AEP East companies and International Transmission Company in Michigan filed a settlement that resolves all hold-harmless issues for a one-time payment of $120,000. Settlement negotiations are in progress with the remaining Michigan companies.

At this time, management is unable to predict the outcome of this proceeding. AEP East companies will support vigorously its positions before the FERC. If the FERC ultimately approves a significant hold-harmless payment to the Michigan utilities, it would adversely impact results of operations and cash flows.
 
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

As discussed in the 2004 Annual Report, certain AEP subsidiaries are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in the 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo

On January 26, 2005, the PUCO approved Rate Stabilization Plans for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for up to 4% of additional annual generation rate increases based on supporting the need for additional revenues. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. First quarter 2005 pretax earnings were increased by $13 million for CSPCo and $32 million for OPCo as a result of implementing this provision of the Rate Stabilization Plans. Of these amounts approximately $8 million for CSPCo and $21 for OPCo relate to 2004 environmental carrying costs and RTO costs.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding their approval of the rate stabilization plans. On March 23, 2005, the PUCO denied all applications for rehearing. In April 2005, an intervenor filed an appeal to the Ohio Supreme Court. Management cannot predict the ultimate impact appeal proceedings will have on the Ohio companies’ future results of operations and cash flows.

TEXAS RESTRUCTURING - Affecting TCC and TNC

The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items in TCC’s future true-up filing. TCC has asked permission from the PUCT to file its True-up Proceeding after the sales of its interest in STP have been concluded, with only the ownership interest in Oklaunion remaining to be settled. If the request is approved, it is anticipated that TCC’s True-up Proceeding will be filed during the second quarter of 2005 seeking recovery of its net regulatory asset of $1.6 billion for its net stranded cost and other true-up items, which it believes the Texas Restructuring Legislation allows.

The Components of TCC’s Net True-up Regulatory Asset as of March 31, 2005 and December 31, 2004 are:

   
TCC
 
   
March 31, 2005
 
December 31, 2004
 
   
(in millions)
 
Stranded Generation Plant Costs
 
$
898
 
$
897
 
Net Generation-related Regulatory Asset
   
249
   
249
 
Unrefunded Excess Earnings
   
(6
)
 
(10
)
Net Stranded Generation Costs
   
1,141
   
1,136
 
Carrying Costs on Stranded Generation Plant Costs
   
205
   
225
 
Net Stranded Generation Costs Designated for Securitization
   
1,346
   
1,361
 
               
Wholesale Capacity Auction True-up
   
483
   
483
 
Carrying Costs on Wholesale Capacity Auction True-up
   
91
   
77
 
Retail Clawback
   
(61
)
 
(61
)
Deferred Over-recovered Fuel Balance
   
(215
)
 
(212
)
Net Other Recoverable True-up Amounts
   
298
   
287
 
Total Recorded Net True-up Regulatory Asset
 
$
1,644
 
$
1,648
 

The Components of TNC’s Net True-up Regulatory Liability as of March 31, 2005 and December 31, 2004 are:

   
TNC
 
   
March 31, 2005
 
December 31, 2004
 
   
(in millions)
 
Retail Clawback
 
$
(14
)
$
(14
)
Deferred Over-recovered Fuel Balance
   
(5
)
 
(4
)
Total Recorded Net True-up Regulatory Liability
 
$
(19
)
$
(18
)

TCC Fuel Reconciliation

On April 14, 2005, the PUCT ruled that specific energy-only purchased power contracts included a capacity component which is not recoverable in fuel rates. In the first quarter of 2005, TCC recorded a provision for fuel revenue refund of $3 million, inclusive of interest, for this decision and continued to accrue interest on the deferred over-recovered fuel balance. This provision for refund results in a deferred over-recovery balance of $215 million as of March 31, 2005.

TCC Carrying Costs on Net True-up Regulatory Assets

TCC continues to accrue a carrying cost at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes (ADFIT) on TCC’s net stranded cost and other true-up items which was applied retroactively to January 1, 2004. In the first quarter of 2005, TCC accrued carrying costs of $21 million which was more than offset by an adjustment based on this order of $27 million. The net reduction of $6 million in carrying costs is included in Nonoperating Income in the first quarter of 2005 on TCC’s accompanying Statements of Income.

As of March 31, 2005, TCC has computed carrying costs of $450 million of which $296 million was recognized as income in 2004 and the first quarter of 2005. The remaining equity component of the carrying costs of $154 million will be recognized in income as collected.

TCC Unrefunded Excess Earnings

At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. In the first quarter of 2005, TCC refunded an additional $4 million reducing its unrefunded excess earnings to $6 million.

TCC True-up Proceeding

When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated T&D rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

The nonaffiliated utility’s March order also provided for the present value of the cost free capital benefits of ADFIT associated with stranded generation costs to be offset against other recoverable true-up amounts when establishing the competition transition charges (CTC). TCC estimates its present value ADFIT benefit to be $212 million based on its current net true-up regulatory asset. TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT in the nonaffiliated utility’s order and determined that the projected cash flows from the transition charges were more than sufficient to recover TCC’s entire net true-up regulatory asset. As a result, no impairment has been recorded. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in its True-up Proceeding, TCC expects to amortize its total net true-up regulatory asset over recovery periods to be established by the PUCT in proceedings subsequent to TCC’s True-up Proceeding.

We believe that our recorded net true-up regulatory asset of $1.6 billion at March 31, 2005 is recoverable under the Texas Restructuring Legislation; however, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered. To the extent decisions of the PUCT in TCC’s future True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated companies, additional material disallowances and reductions of recorded carrying costs are possible, which could have a material adverse effect on TCC’s future results of operations, cash flows and possibly financial condition.

TNC True-Up Proceeding

In January 2005, intervenors made various recommendations including an increase in excess earnings of $5 million and a T&D rate reduction of $3 million annually. The intervenors also recommended that TNC’s fuel over-recovery should be increased by $2 million. TNC is awaiting a PUCT decision and order and has recorded no disallowances based on intervenor contentions.

In 2004, TNC appealed to the state and federal courts the PUCT’s order in its final fuel reconciliation covering the period from July 2000 through December 31, 2001. In March 2005, the ALJ made certain recommendations regarding the deferred fuel balance resulting in an additional provision for refund of $1 million, which results in an over-recovery amount of $5 million. TNC will pursue vigorously its appeals, but cannot predict their outcome.


5. COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within the 2004 Annual Report, certain Registrant Subsidiaries continue to be involved in various legal matters. The 2004 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since their disclosure in the 2004 Annual Report. The matters discussed in the 2004 Annual Report without significant changes in status since year-end include, but are not limited to, (1) carbon dioxide public nuisance claims, (2) nuclear matters, (3) construction commitments, (4) potential uninsured losses, and (5) FERC long-term contracts. See disclosure below for significant matters with changes in status subsequent to the disclosure made in the 2004 Annual Report.

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at the generating units over a 20-year period.

Under the CAA, 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 CAA 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.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaint and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern States each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. These complaints have been assigned to the same judge in the Southern District Court. AEP filed an answer to the complaint in January 2005, denying the allegations and stating its defenses.

In August 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, a nonaffiliated 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 nonroutine 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 settlement between Ohio Edison, the Federal EPA and other parties to the litigation will avoid further litigation and result in expenditures at its plant.

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.

In August 2003, the District Court for the Middle District of South Carolina issued a decision in a case pending against Duke Energy Corporation, a nonaffiliated utility. The District Court 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. The Federal EPA requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals. The District Court denied the Federal EPA’s motion. In April 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that eliminated the need for a trial, but preserving plaintiffs’ right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. The United States subsequently filed a notice of appeal to the Fourth Circuit Court of Appeals. The case is fully briefed and oral argument was heard in February 2005.

In June 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 alleged CAA 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 CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court and on May 3, 2004, that petition was denied.

In June 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. Briefing continues in this case and oral argument was held in January 2005.

In December 2000, Cinergy Corp., a nonaffiliated 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.

In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power & Light Company in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio state implementation plan occurred at the J.M. Stuart Station, and seeking injunctive relief and civil penalties. CSPCo owns a 26% share of the J.M. Stuart Station. The owners have filed a motion to dismiss portions of the complaint, based primarily upon the federal statute of limitations. In March 2005, in an unrelated case alleging new source review permitting claims against TVA, the court granted a motion to dismiss the claims against TVA on similar grounds. The owners have advised the court of this new decision. Management believes the allegations in the complaint are without merit, and intends to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

Management is unable to estimate the loss or range of loss related to any contingent liability for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment 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.

SWEPCo Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and Pirkey plants. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo will file a response to the complaint in May.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of $228,312 against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the references to a specific heat input value for each Welsh unit.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of $5,550 against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, financial condition or cash flows.

OPERATIONAL

Power Generation Facility - Affecting OPCo

AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP has subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 270 MW). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo has also agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.) (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

In September 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleges that TEM has breached the PPA, and is seeking a determination of OPCo’s rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of OPCo’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, OPCo could be adversely affected to the extent it is unable to find other purchasers of the power with similar contractual terms and to the extent OPCo does not fully recover claimed termination value damages from TEM. However, OPCo has entered an agreement with an affiliate that eliminates OPCo’s market exposure related to the PPA. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) has provided a limited guaranty.

In November 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted OPCo partial summary judgment on this issue, holding that the absences of operating protocols does not prevent enforcement of the PPA.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for these electric power products under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM, and SUEZ-TRACTEBEL S.A. under the guaranty, damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005.

Merger Litigation-Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and will file a petition for review of this Initial Decision. The SEC will review the Initial Decision.
 
Enron Bankruptcy -Affecting APCo, CSPCo, I&M, KPCo and OPCo

In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding 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, AEP purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - Commodity trading settlement disputes - 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 in connection with gas-related trading transactions. The AEP subsidiaries have asserted their right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in nonbinding court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding court-sponsored mediation.

Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy 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. As noted above, Enron has challenged the offsetting of receivables and payables. Although management is unable to predict the outcome of these lawsuits it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.
 
Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC

Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP), filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003 against AEP and four of its subsidiaries, including TCC and TNC, certain nonaffiliated 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. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, sought leave to intervene as plaintiffs asserting similar claims. AEP and its subsidiaries filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. AEP and its subsidiaries filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit. In April 2005, the defendants filed a Motion to Stay this case, pending the outcome of the appeal in the TCE case.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, have disputed transportation costs for coal received between July 2000 and the present time. The joint plant has remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded provisions for possible loss in December 2004 and the first quarter of 2005. The provisions were deferred as a regulatory asset under PSO’s fuel mechanism and affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.


6. GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letter of Credit

Certain Registrant Subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover insurance programs, security deposits, debt service reserves, and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At March 31, 2005, the maximum future payments of the LOCs include $44 million, $1 million, $51 million, $4 million and $43 million for CSPCo, I&M, OPCo, SWEPCo and TCC, respectively, with maturities ranging from November 2005 to April 2007. 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 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 $51 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 March 31, 2005, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

SWEPCo consolidates Sabine due to the application of FIN 46. SWEPCo does not have an ownership interest in Sabine.

Indemnifications and Other Guarantees

Contracts

All of the Registrant Subsidiaries enter into certain 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. Registrant 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 2004 and the first quarter of 2005, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except for TCC which entered into an indemnification of $129 million relating to the sale of its generation assets in July 2004. There are no material liabilities recorded for any indemnifications.

Registrant Subsidiaries are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and for activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Master Operating Lease

Certain Registrant 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, the subsidiary has 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, 2005, 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
 
$
5
 
CSPCo
   
2
 
I&M
   
3
 
KPCo
   
1
 
OPCo
   
5
 
PSO
   
4
 
SWEPCo
   
4
 
TCC
   
6
 
TNC
   
3
 


7. DISPOSITIONS AND ASSETS HELD FOR SALE

DISPOSITIONS ANTICIPATED BEING COMPLETED DURING 2005

Texas Plants - Oklaunion Power Station

In January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to an unrelated party. In May 2004, TCC received notice from the two nonaffiliated co-owners of the Oklaunion Power Station, announcing their decision to exercise their right of first refusal, with terms similar to the original agreement. In June 2004 and September 2004, TCC entered into sales agreements with both of its nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. These agreements are currently being challenged in Dallas County, Texas State District Court by the unrelated party with which TCC entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. TCC cannot predict when these issues will be resolved. TCC does not expect the sale to have a significant effect on its results of operations. TCC’s assets and liabilities related to the Oklaunion Power Station have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Consolidated Balance Sheets at March 31, 2005 and December 31, 2004.

Texas Plants - South Texas Project

In February 2004, TCC signed an agreement to sell its 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, TCC received notice from co-owners of their decisions to exercise their rights of first refusal, with terms similar to the original agreement. In September 2004, TCC entered into sales agreements with two of its nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. TCC expects the sale to close in the second quarter of 2005. TCC’s assets and liabilities related to STP have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Consolidated Balance Sheets at March 31, 2005 and December 31, 2004.

The assets and liabilities of the TCC plants held for sale at March 31, 2005 and December 31, 2004 are as follows:

   
Texas Plants
 
   
March 31, 2005