**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.
      EmployerFile
      Number
    
    Address
      of Principal Executive Offices, and Telephone Number
    
    Identification
      No.1-3525
    
    AMERICAN
      ELECTRIC POWER COMPANY, INC. (A New York Corporation)
    
    13-49226400-18135
    
    AEP
      GENERATING COMPANY (An Ohio Corporation)
    
    31-10338330-346
    
    AEP
      TEXAS CENTRAL COMPANY (A Texas Corporation)
    
    74-05506000-340
    
    AEP
      TEXAS NORTH COMPANY (A Texas Corporation)
    
    75-06467901-3457
    
    APPALACHIAN
      POWER COMPANY (A Virginia Corporation)
    
    54-01247901-2680
    
    COLUMBUS
      SOUTHERN POWER COMPANY (An Ohio Corporation)
    
    31-41542031-3570
    
    INDIANA
      MICHIGAN POWER COMPANY (An Indiana Corporation)
    
    35-04104551-6858
    
    KENTUCKY
      POWER COMPANY (A Kentucky Corporation)
    
    61-02477751-6543
    
    OHIO
      POWER COMPANY (An Ohio Corporation)
    
    31-42710000-343
    
    PUBLIC
      SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
    
    73-04108951-3146
    
    SOUTHWESTERN
      ELECTRIC POWER COMPANY (A Delaware Corporation)
    
    72-0323455All
      Registrants
    
    1
      Riverside Plaza, Columbus, Ohio 43215-2373Telephone
      (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.
    
    
    384,020,319AEP
      Generating Company
    
    
    1,000AEP
      Texas Central Company
    
    
    2,211,678AEP
      Texas North Company
    
    
    5,488,560Appalachian
      Power Company
    
    
    13,499,500Columbus
      Southern Power Company
    
    
    16,410,426Indiana
      Michigan Power Company
    
    
    1,400,000Kentucky
      Power Company
    
    
    1,009,000Ohio
      Power Company
    
    
    27,952,473Public
      Service Company of Oklahoma
    
    
    9,013,000Southwestern
      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 TermsForward-Looking
      InformationPart
      I. FINANCIAL INFORMATIONItems
      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 OperationsQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial StatementsNotes
      to Consolidated Financial Statements**AEP
      Generating Company:**Management’s
      Narrative Financial Discussion and AnalysisFinancial
      Statements**AEP
      Texas Central Company and Subsidiary:**Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial Statements**AEP
      Texas North Company:**Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesFinancial
      Statements**Appalachian
      Power Company and Subsidiaries:**Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial Statements**Columbus
      Southern Power Company and Subsidiaries:**Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial Statements**Indiana
      Michigan Power Company and Subsidiaries:**Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial Statements**Kentucky
      Power Company:**Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesFinancial
      Statements**Ohio
      Power Company Consolidated:**Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial Statements
  **Public
      Service Company of Oklahoma:**Management’s
      Narrative Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesFinancial
      Statements**Southwestern
      Electric Power Company Consolidated:**Management’s
      Financial Discussion and AnalysisQuantitative
      and Qualitative Disclosures About Risk Management
    ActivitiesConsolidated
      Financial StatementsNotes
      to Financial Statements of Registrant SubsidiariesCombined
      Management’s Discussion and Analysis of Registrant
      SubsidiariesItem
      4.
    
    Controls
      and ProceduresPart
      II. OTHER INFORMATIONItem
      1.
    
    Legal
      ProceedingsItem
      2.
    
    Unregistered
      Sales of Equity Securities and Use of ProceedsItem
      5.
    
    Other
      InformationItem
      6.
    
    ExhibitsExhibits:Exhibit
      4 (a)Exhibit
      10 (a)Exhibit
      10 (b)Exhibit
      12Exhibit
      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**
    
    **M****eaning**
 
 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 OhioPUCT
    
    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 energysupply
      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
    
    $
    0.77Investments
      - Gas Operations
    
    
    10
    
    
    0.03
    
    
    (10
    )
    
    (0.03
    )Investments
      - Other
    
    
    5
    
    
    0.01
    
    
    4
    
    
    0.01All
      Other****(a)
    
    
    (14
    )
    
    (0.04
    )
    
    (9
    )
    
    (0.02
    )**Income
      Before Discontinued Operations**
    
    
    354
    
    
    0.90
    
    
    289
    
    
    0.73Investments
      - 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
    
    $
    2,602Fuel
      and Purchased Power
    
    
    905
    
    
    779**Gross
      Margin**
    
    
    1,709
    
    
    1,823Depreciation
      and Amortization
    
    
    318
    
    
    310Other
      Operating Expenses
    
    
    871
    
    
    888**Operating
      Income**
    
    
    520
    
    
    625Other
      Income (Expense), Net
    
    
    148
    
    
    9Interest
      Expenses and Preferred Stock Dividend Requirements
    
    
    144
    
    
    166Income
      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
    
    
    13,427Commercial
    
    
    8,732
    
    
    8,779Industrial
    
    
    12,774
    
    
    12,273Miscellaneous
    
    
    645
    
    
    743Subtotal
    
    
    35,375
    
    
    35,222Texas
      Retail and Other
    
    
    228
    
    
    224**Total**
    
    
    35,603
    
    
    35,446Wholesale
    
    
    12,635
    
    
    13,851Texas
      Wires Delivery
    
    
    5,519
    
    
    5,490
  
 **2005**
    
    **2004****Weather
      Summary**
    
    **(in
      degree days)**Eastern
      RegionActual
      - Heating
    
    
    1,774
    
    
    1,864Normal
      - Heating****(a)
    
    
    1,811
    
    
    1,806Actual
      - Cooling
    
    
    -
    
    
    3Normal
      - Cooling****(a)
    
    
    3
    
    
    3Western
      Region(b)Actual
      - Heating
    
    
    769
    
    
    883Normal
      - Heating****(a)
    
    
    973
    
    
    978Actual
      - Cooling
    
    
    20
    
    
    30Normal
      - 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
    
    
    21Depreciation
      and Amortization
    
    
    (8
    )Taxes
      Other Than Income Taxes
    
    
    (4
    )Other
      Income (Expense), Net
    
    
    139Interest
      Expenses
    
    
    22170Income
      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
    
    
    0.3Cumulative
      Preferred Stock (Subject to Mandatory Redemption)
    
    
    -
    
    
    -
    
    
    66
    
    
    0.3Long-term
      Debt, including amounts due within one year
    
    
    12,359
    
    
    59.7
    
    
    12,287
    
    
    58.7Short-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
      2007Revolving
      Credit Facility
    
    
    1,500
    
    
    March
      2010Letter
      of Credit Facility
    
    
    200
    
    
    September
      2006**Total**
    
    
    2,700Cash
      and Cash Equivalents
    
    
    1,261**Total
      Liquidity Sources**
    
    
    3,961Less:
      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-2Senior
      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
    
    $
    778Cash
      flows from (used for):Operating
      activities
    
    
    673
    
    
    897Investing
      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
    
    $
    282Plus:
      Loss From Discontinued Operations
    
    
    (1
    )
    
    7**Income
      from Continuing Operations**
    
    
    354
    
    
    289Noncash
      Items Included in Earnings
    
    
    243
    
    
    222Changes
      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
    
    
    64Proceeds
      from Sales of Assets
    
    
    1,157
    
    
    40Other
    
    
    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
    
    $
    10Repurchase
      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 SO*** ***2*** ***,
NO*** ***x*** ***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
SO 2 ,
NO x 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
      SO2and NOxemissions 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 NO x control
program as well as an annual SO 2 control
program. All of the states in which our generating facilities are located will
be subject to the regional and annual NO x control
programs and the annual SO 2 control
program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the
annual programs only. Arkansas will be subject to the seasonal NO x control
program only. Oklahoma is not affected by CAIR. In addition, the compliance
deadline for Phase I for the NO x control
program has been accelerated to 2009, and will replace any obligations imposed
by the NO x 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 ContractsRealized/Settled
      During the Period (a)
    
    
    (37
    )
    
    (5
    )
    
    12
    
    
    (30
    )Fair
      Value of New Contracts WhenEntered
      During the Period (b)
    
    
    1
    
    
    -
    
    
    -
    
    
    1Net
      Option Premiums Paid/(Received) (c)
    
    
    -
    
    
    -
    
    
    -
    
    
    -Change
      in Fair Value Due to ValuationMethodology
      Changes
    
    
    -
    
    
    -
    
    
    -
    
    
    -Changes
      in Fair Value of RiskManagement
      Contracts (d)
    
    
    29
    
    
    (5
    )
    
    -
    
    
    24Changes
      in Fair Value of RiskManagement
      Contracts Allocated to
      Regulated
      Jurisdictions (e)
    
    
    (8
    )
    
    -
    
    
    -
    
    
    (8
    )**Total
      MTM Risk Management Contract****Net
      Assets**
      **(Liabilities) at****March
      31, 2005**
    
    $
    262
    
    $
    (10
    )
    $
    -
    
    
    252Net
      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
    
    $
    836Noncurrent
      Assets
    
    
    497
    
    
    146
    
    
    643**Total
      Assets**
    
    
    1,042
    
    
    437
    
    
    1,479Current
      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
    
    $
    865Noncurrent
      Assets
    
    
    643
    
    
    3
    
    
    646**Total
      MTM Derivative Contract Assets**
    
    
    1,479
    
    
    32
    
    
    1,511Current
      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 - ExchangeTraded
      Contracts
    
    $
    (67
    )
    $
    18
    
    $
    22
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    (27
    )Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    131
    
    
    63
    
    
    46
    
    
    21
    
    
    -
    
    
    -
    
    
    261Prices
      Based on Models and OtherValuation
      Methods (b)
    
    
    (2
    )
    
    (36
    )
    
    (13
    )
    
    20
    
    
    31
    
    
    28
    
    
    28**Total**
    
    $
    62
    
    $
    45
    
    $
    55
    
    $
    41
    
    $
    31
    
    $
    28
    
    $
    262**Investments
      - Gas Operations:**Prices
      Actively Quoted - ExchangeTraded
      Contracts
    
    $
    34
    
    $
    (7
    )
    $
    4
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    31Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    (21
    )
    
    (3
    )
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    (24
    )Prices
      Based on Models and OtherValuation
      Methods (b)
    
    
    (3
    )
    
    (3
    )
    
    (3
    )
    
    (2
    )
    
    (4
    )
    
    (2
    )
    
    (17
    )**Total**
    
    $
    10
    
    $
    (13
    )
    $
    1
    
    $
    (2
    )
    $
    (4
    )
    $
    (2
    )
    $
    (10
    )**Total:**Prices
      Actively Quoted - ExchangeTraded
      Contracts
    
    $
    (33
    )
    $
    11
    
    $
    26
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    4Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    110
    
    
    60
    
    
    46
    
    
    21
    
    
    -
    
    
    -
    
    
    237Prices
      Based on Models and OtherValuation
      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
    
    60Physical
      Forwards
    
    Gulf
      Coast, Texas
    
    24Swaps
    
    Gas
      East - Northeast, Mid-continent, Gulf
      Coast, Texas
    
    24Swaps
    
    Gas
      West - Rocky Mountains, West Coast
    
    24Exchange
      Option Volatility
    
    NYMEX/Henry
      Hub
    
    12Power
    
    Futures
    
    Power
      East - PJM
    
    36Physical
      Forwards
    
    Power
      East - Cinergy
    
    21Physical
      Forwards
    
    Power
      East - PJM West
    
    33Physical
      Forwards
    
    Power
      East - AEP Dayton (PJM)
    
    21Physical
      Forwards
    
    Power
      East - NEPOOL
    
    21Physical
      Forwards
    
    Power
      East - NYPP
    
    33Physical
      Forwards
    
    Power
      East - ERCOT
    
    48Physical
      Forwards
    
    Power
      East - Com Ed
    
    21Physical
      Forwards
    
    Power
      West - Palo Verde, North Path 15,South
      Path 15,
      MidColumbia, Mead
    
    45Peak
      Power Volatility (Options)
    
    Cinergy
    
    12Peak
      Power Volatility (Options)
    
    PJM
    
    12Crude
      Oil
    
    Swaps
    
    West
      Texas Intermediate
    
    36Emissions
    
    Credits
    
    SO2,NOx
    
    45Coal
    
    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
    
    $
    97Split
      Rating
    
    
    18
    
    
    7
    
    
    11
    
    
    2
    
    
    11Noninvestment
      Grade
    
    
    269
    
    
    143
    
    
    126
    
    
    3
    
    
    93No
      External Ratings:Internal
      Investment Grade
    
    
    44
    
    
    -
    
    
    44
    
    
    2
    
    
    32Internal
      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-DayHolding
      Period
    
    $
    8
    
    $
    9
    
    $
    17
    
    $
    599%
      Confidence Level, One-DayHolding
      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
    
    $
    2,581Gas
      Operations
    
    
    357
    
    
    652Other
    
    
    89
    
    
    131**TOTAL**
    
    
    2,983
    
    
    3,364**EXPENSES**Fuel
      for Electric Generation
    
    
    771
    
    
    694Purchased
      Electricity for Resale
    
    
    130
    
    
    83Purchased
      Gas for Resale
    
    
    249
    
    
    585Maintenance
      and Other Operation
    
    
    790
    
    
    864Depreciation
      and Amortization
    
    
    327
    
    
    319Taxes
      Other Than Income Taxes
    
    
    188
    
    
    193**TOTAL**
    
    
    2,455
    
    
    2,738**OPERATING
      INCOME**
    
    
    528
    
    
    626Other
      Income
    
    
    239
    
    
    62Other
      Expense
    
    
    (66
    )
    
    (36
    )**INTEREST
      AND OTHER CHARGES**Interest
      Expense
    
    
    173
    
    
    199Preferred
      Stock Dividend Requirements of Subsidiaries
    
    
    2
    
    
    2**TOTAL**
    
    
    175
    
    
    201**INCOME
      BEFORE INCOME TAXES**
    
    
    526
    
    
    451Income
      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
    
    $
    0.73Discontinued
      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
    
    $
    320Other
      Temporary Cash Investments
    
    
    181
    
    
    275Accounts
      Receivable:Customers
    
    
    847
    
    
    930Accrued
      Unbilled Revenues
    
    
    256
    
    
    592Miscellaneous
    
    
    65
    
    
    79Allowance
      for Uncollectible Accounts
    
    
    (43
    )
    
    (77
    )Total Receivables
    
    
    1,125
    
    
    1,524Fuel,
      Materials and Supplies
    
    
    636
    
    
    852Risk
      Management Assets
    
    
    865
    
    
    737Margin
      Deposits
    
    
    178
    
    
    113Other
    
    
    157
    
    
    200**TOTAL**
    
    
    4,403
    
    
    4,021**PROPERTY,
      PLANT AND EQUIPMENT**Electric:Production
    
    
    16,019
    
    
    15,969Transmission
    
    
    6,310
    
    
    6,293Distribution
    
    
    10,378
    
    
    10,280Other
      (including gas, coal mining and nuclear fuel)
    
    
    3,152
    
    
    3,585Construction
      Work in Progress
    
    
    1,329
    
    
    1,159**Total**
    
    
    37,188
    
    
    37,286Accumulated
      Depreciation and Amortization
    
    
    14,589
    
    
    14,485**TOTAL
      - NET**
    
    
    22,599
    
    
    22,801**OTHER
      NONCURRENT ASSETS**Regulatory
      Assets
    
    
    3,653
    
    
    3,601Securitized
      Transition Assets
    
    
    632
    
    
    642Spent
      Nuclear Fuel and Decommissioning Trusts
    
    
    1,080
    
    
    1,053Investments
      in Power and Distribution Projects
    
    
    136
    
    
    154Goodwill
    
    
    76
    
    
    76Long-term
      Risk Management Assets
    
    
    646
    
    
    470Prepaid
      Pension Obligations
    
    
    385
    
    
    386Other
    
    
    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
    
    $
    1,051Short-term
      Debt
    
    
    
    19
    
    
    23Long-term
      Debt Due Within One Year (a)
    
    
    
    1,685
    
    
    1,279Cumulative
      Preferred Stocks of Subsidiaries Subject to Mandatory Redemption
    
    
    
    -
    
    
    66Risk
      Management Liabilities
    
    
    
    850
    
    
    608Accrued
      Taxes
    
    
    
    865
    
    
    611Accrued
      Interest
    
    
    
    171
    
    
    180Customer
      Deposits
    
    
    
    469
    
    
    414Other
    
    
    
    597
    
    
    775**TOTAL**
    
    
    
    5,532
    
    
    5,007**NONCURRENT
      LIABILITIES**Long-term
      Debt (a)
    
    
    
    10,674
    
    
    11,008Long-term
      Risk Management Liabilities
    
    
    
    470
    
    
    329Deferred
      Income Taxes
    
    
    
    4,774
    
    
    4,819Regulatory
      Liabilities and Deferred Investment Tax Credits
    
    
    
    2,616
    
    
    2,540Asset
      Retirement Obligations
    
    
    
    841
    
    
    827Employee
      Benefits and Pension Obligations
    
    
    
    632
    
    
    730Deferred
      Gain on Sale and Leaseback - Rockport Plant Unit 2
    
    
    
    164
    
    
    166Deferred
      Credits and Other
    
    
    
    810
    
    
    411**TOTAL**
    
    
    
    20,981
    
    
    20,830**Liabilities
      Held for Sale**
    
    
    
    255
    
    
    250**TOTAL
      LIABILITIES**
    
    
    
    26,768
    
    
    26,087Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    
    61
    
    
    61Commitments
      and Contingencies (Note 5)**COMMON
      SHAREHOLDERS’ EQUITY**Common
      Stock Par Value $6.50:2005
    
    2004Shares
      Authorized
    600,000,000
    
    600,000,000Shares
      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
    
    
    2,632Paid-in
      Capital
    
    
    
    3,786
    
    
    4,203Retained
      Earnings
    
    
    
    2,241
    
    
    2,024Accumulated
      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
    
    $
    282Plus:
      (Income) Loss from Discontinued Operations
    
    
    (1
    )
    
    7**Income
      from Continuing Operations**
    
    
    354
    
    
    289**Adjustments
      for Noncash Items:**Depreciation
      and Amortization
    
    
    327
    
    
    319Accretion
      of Asset Retirement Obligations
    
    
    18
    
    
    15Deferred
      Income Taxes
    
    
    (19
    )
    
    49Deferred
      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
    
    
    30Gain
      on Sales of Assets
    
    
    (115
    )
    
    (1
    )Change
      in Other Noncurrent Assets
    
    
    (66
    )
    
    2Change
      in Other Noncurrent Liabilities
    
    
    (64
    )
    
    10**Changes
      in Certain Components of Working Capital:**Accounts
      Receivable, Net
    
    
    104
    
    
    183Fuel,
      Materials and Supplies
    
    
    64
    
    
    65Accounts
      Payable
    
    
    39
    
    
    (95
    )Taxes
      Accrued
    
    
    245
    
    
    189Customer
      Deposits
    
    
    55
    
    
    43Interest
      Accrued
    
    
    (9
    )
    
    (10
    )Other
      Current Assets
    
    
    (8
    )
    
    5Other
      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
    
    
    64Investment
      in Discontinued Operations, Net
    
    
    -
    
    
    7Proceeds
      from Sale of Assets
    
    
    1,157
    
    
    40Other
    
    
    2
    
    
    8**Net
      Cash Flows From (Used For) Investing Activities**
    
    
    788
    
    
    (186
    )**FINANCING
      ACTIVITIES**Issuance
      of Common Stock
    
    
    17
    
    
    10Repurchase
      of Common Stock
    
    
    (434
    )
    
    -Issuance
      of Long-term Debt
    
    
    580
    
    
    73Change
      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
    )
    $
    7,874Issuance
      of Common Stock
    
    
    1
    
    
    4
    
    
    6
    
    
    
    
    
    
    
    
    10Common
      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
    
    
    8Cash
      Flow Hedges, Net of Tax of $12
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    22
    
    
    22Minimum
      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
    )
    $
    8,515Issuance
      of Common Stock
    
    
    
    
    
    3
    
    
    14
    
    
    
    
    
    
    
    
    17Common
      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
    
    
    1Cash
      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
    
    $
    417Defeased
      TCC First Mortgage Bonds (a)
    
    
    84
    
    
    84Installment
      Purchase Contracts
    
    
    1,935
    
    
    1,773Notes
      Payable
    
    
    935
    
    
    939Senior
      Unsecured Notes
    
    
    7,667
    
    
    7,717Securitization
      Bonds
    
    
    669
    
    
    698Notes
      Payable to Trust
    
    
    113
    
    
    113Equity
      Unit Senior Notes
    
    
    345
    
    
    345Long-term
      DOE Obligation (b)
    
    
    230
    
    
    229Other
      Long-term Debt
    
    
    8
    
    
    14Equity
      Unit Contract Adjustment Payments
    
    
    7
    
    
    9Unamortized
      Discount (net)
    
    
    (51
    )
    
    (51
    )**TOTAL
      LONG-TERM DEBT OUTSTANDING**
    
    
    12,359
    
    
    12,287Less
      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 Matters2.
    New
      Accounting Pronouncements3.
    Rate
      Matters4.
    Customer
      Choice and Industry Restructuring5.
    Commitments
      and Contingencies6.
    Guarantees7.
    Dispositions,
      Discontinued Operations and Assets Held for Sale8.
    Benefit
      Plans9.
    Business
      Segments10.
    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
    
    $
    6Equity
      Earnings
    
    
    5
    
    
    7Nonutility
      Revenue
    
    
    63
    
    
    29Gain
      on Sale of Texas REPs
    
    
    112
    
    
    -Carrying
      Charges
    
    
    20
    
    
    2Other
    
    
    28
    
    
    18**Total
      Other Income**
    
    $
    239
    
    $
    62**Other
      Expense:**Nonutility
      Expense
    
    $
    57
    
    $
    26Other
    
    
    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
    
    $
    6Securities
      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
    
    $
    1,076Accretion
      Expense
    
    
    16
    
    
    2
    
    
    -
    
    
    18Asset
      Retirement Obligation Liability at   March 31, 2005 Including
      Held for Sale
    
    
    976
    
    
    86
    
    
    32
    
    
    1,094Less
      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
    
    $
    23Proceeds
      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
    
    $
    0.70Effect
      of Medicare Subsidy
    
    
    4
    
    
    0.01Restated
    
    $
    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 SO 2 and
NO x 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
    
    $
    897Net
      Generation-related Regulatory Asset
    
    
    249
    
    
    249Unrefunded
      Excess Earnings
    
    
    (6
    )
    
    (10
    )**Net
      Stranded Generation Costs**
    
    
    1,141
    
    
    1,136Carrying
      Costs on Stranded Generation Plant Costs
    
    
    205
    
    
    225**Net
      Stranded Generation Costs Designated for
      Securitization**
    
    
    1,346
    
    
    1,361Wholesale
      Capacity Auction True-up
    
    
    483
    
    
    483Carrying
      Costs on Wholesale Capacity Auction True-up
    
    
    91
    
    
    77Retail
      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
    )2005Income (Loss) After tax
    
    
    6
    
    
    (5
    )
    
    1
 
 **Pushan
      Power Plant**
    
    **LIG
      (c)**
    
    **U.K.
      Operations**
    
    **Total**2004
      Revenue
    
    $
    10
    
    $
    160
    
    $
    41
    
    $
    2112004
      Pretax Income (Loss)
    
    
    -
    
    
    (1
    )
    
    (19
    )
    
    (20
    )2004Income (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
    
    $
    24Property,
      Plant and Equipment, Net
    
    
    416
    
    
    413Regulatory
      Assets
    
    
    52
    
    
    48Nuclear
      Decommissioning Trust Fund
    
    
    143
    
    
    143**Total
      Assets Held for Sale**
    
    $
    636
    
    $
    628**Liabilities:**Regulatory
      Liabilities
    
    $
    1
    
    $
    1Asset
      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
    
    $
    10Interest
      Cost
    
    
    56
    
    
    56
    
    
    27
    
    
    29Expected
      Return on Plan Assets
    
    
    (77
    )
    
    (72
    )
    
    (23
    )
    
    (20
    )Amortization
      of Transition (Asset) Obligation
    
    
    -
    
    
    -
    
    
    7
    
    
    7Amortization
      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
    
    $
    -
    
    $
    -
    
    $
    2,983Other
      Operating Segments
    
    
    77
    
    
    (73
    )
    
    -
    
    
    
    3
    
    
    1
    
    
    (8
    )
    
    -Total
      Revenues
    
    $
    2,614
    
    $
    284
    
    $
    -
    
    
    $
    92
    
    $
    1
    
    $
    (8
    )
    $
    2,983Income
      (Loss) Before Discontinued   Operations
    
    $
    353
    
    $
    10
    
    $
    -
    
    
    $
    5
    
    $
    (14
    )
    $
    -
    
    $
    354Discontinued
      Operations, Net of Tax
    
    
    -
    
    
    -
    
    
    (5
    )
    
    
    6
    
    
    -
    
    
    -
    
    
    1Net
      Income (Loss)
    
    $
    353
    
    $
    10
    
    $
    (5
    )
    
    $
    11
    
    $
    (14
    )
    $
    -
    
    $
    355**As
      of March 31, 2005**Total
      Property, Plant and Equipment
    
    $
    36,348
    
    $
    2
    
    $
    -
    
    
    $
    835
    
    $
    3
    
    $
    -
    
    $
    37,188Accumulated
      Depreciation and   Amortization
    
    
    14,494
    
    
    1
    
    
    -
    
    
    
    93
    
    
    1
    
    
    -
    
    
    14,589Total
      Property, Plant and Equipment -   Net
    
    $
    21,854
    
    $
    1
    
    $
    -
    
    
    $
    742
    
    $
    2
    
    $
    -
    
    $
    22,599Total
      Assets
    
    $
    32,655
    
    $
    1,295
    
    $
    597
    (c)
    
    $
    1,557
    
    $
    10,740
    
    $
    (11,747
    )
    $
    35,097Assets
      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
    
    $
    -
    
    $
    -
    
    $
    3,364Other
      Operating Segments
    
    
    21
    
    
    24
    
    
    -
    
    
    
    16
    
    
    6
    
    
    (67
    )
    
    -Total
      Revenues
    
    $
    2,602
    
    $
    676
    
    $
    -
    
    
    $
    147
    
    $
    6
    
    $
    (67
    )
    $
    3,364Income
      (Loss) Before Discontinued
      Operations
    
    $
    304
    
    $
    (10
    )
    $
    -
    
    
    $
    4
    
    $
    (9
    )
    $
    -
    
    $
    289Discontinued
      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
    
    $
    -
    
    $
    37,286Accumulated
      Depreciation and   Amortization
    
    
    14,355
    
    
    43
    
    
    -
    
    
    
    86
    
    
    1
    
    
    -
    
    
    14,485Total
      Property, Plant and Equipment -   Net
    
    $
    21,651
    
    $
    402
    
    $
    -
    
    
    $
    746
    
    $
    2
    
    $
    -
    
    $
    22,801Total
      Assets
    
    $
    32,175
    
    $
    1,789
    
    $
    221
    (c)
    
    $
    2,071
    
    $
    8,093
    
    $
    (9,686
    )
    $
    34,663Assets
      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%
    
    
    2015OPCo
    
    
    Installment
      Purchase Contracts
    
    
    164
    
    
    
    Variable
    
    
    2028OPCo
    
    
    Installment
      Purchase Contracts
    
    
    54
    
    
    
    Variable
    
    
    2029TCC
    
    
    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
    
    
    2007AEP
      and Subsidiaries
    
    
    Other
    
    
    6
    (b)
    
    
    Variable
    
    
    VariousOPCo
    
    
    Installment
      Purchase Contracts
    
    
    102
    
    
    
    6.375%
    
    
    2029OPCo
    
    
    Installment
      Purchase Contracts
    
    
    80
    
    
    
    Variable
    
    
    2028OPCo
    
    
    Installment
      Purchase Contracts
    
    
    36
    
    
    
    Variable
    
    
    2029OPCo
    
    
    Notes
      Payable
    
    
    1
    
    
    
    6.81%
    
    
    2008OPCo
    
    
    Notes
      Payable
    
    
    3
    
    
    
    6.27%
    
    
    2009SWEPCo
    
    
    Notes
      Payable
    
    
    2
    
    
    
    4.47%
    
    
    2011SWEPCo
    
    
    Notes
      Payable
    
    
    1
    
    
    
    Variable
    
    
    2008TCC
    
    
    Senior
      Unsecured Notes
    
    
    150
    
    
    
    3.00%
    
    
    2005TCC
    
    
    Senior
      Unsecured Notes
    
    
    100
    
    
    
    Variable
    
    
    2005TCC
    
    
    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
    
    $
    13I&M
    
    
    6.250%
    
    
    192,500
    
    
    19I&M
    
    
    6.875%
    
    
    157,500
    
    
    16I&M
    
    
    6.300%
    
    
    132,450
    
    
    13OPCo
    
    
    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
    
    
    3.8Depreciation
      and Amortization
    
    
    (0.2
    )Taxes
      Other Than Income Taxes
    
    
    (0.1
    )Interest
      Charges
    
    
    (0.1
    )**Total
      Change in Operating Expenses and Other**
    
    
    
    
    
    3.4Income
      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
    
    
    21,398Rent
      - Rockport Plant Unit 2
    
    
    17,071
    
    
    17,071Other
      Operation
    
    
    2,385
    
    
    2,490Maintenance
    
    
    1,718
    
    
    5,400Depreciation
      and Amortization
    
    
    5,956
    
    
    5,734Taxes
      Other Than Income Taxes
    
    
    1,024
    
    
    944Income
      Taxes
    
    
    936
    
    
    698**TOTAL**
    
    
    64,225
    
    
    53,735**OPERATING
      INCOME**
    
    
    2,321
    
    
    1,547Nonoperating
      Income
    
    
    -
    
    
    24Nonoperating
      Expenses
    
    
    64
    
    
    69Nonoperating
      Income Tax Credit
    
    
    891
    
    
    857Interest
      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
    
    $
    21,441Net
      Income
    
    
    2,516
    
    
    1,827Cash
      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
    
    $
    681,254General
    
    
    3,923
    
    
    3,739Construction
      Work in Progress
    
    
    6,990
    
    
    7,729**Total**
    
    
    693,075
    
    
    692,722Accumulated
      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
    
    
    23,078Fuel
    
    
    10,613
    
    
    16,404Materials
      and Supplies
    
    
    6,337
    
    
    5,962Prepayments
    
    
    35
    
    
    -**TOTAL**
    
    
    41,233
    
    
    45,444**DEFERRED
      DEBITS AND OTHER ASSETS**Regulatory
      Assets:Unamortized
      Loss on Reacquired Debt
    
    
    4,437
    
    
    4,496Asset
      Retirement Obligations
    
    
    1,165
    
    
    1,117Deferred
      Property Taxes
    
    
    3,441
    
    
    557Other
      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
    
    $
    1,000Paid-in
      Capital
    
    
    23,434
    
    
    23,434Retained
      Earnings
    
    
    25,813
    
    
    24,237**Total
      Common Shareholder’s Equity**
    
    
    50,247
    
    
    48,671Long-term
      Debt
    
    
    44,822
    
    
    44,820**TOTAL**
    
    
    95,069
    
    
    93,491**CURRENT
      LIABILITIES**Advances
      from Affiliates
    
    
    7,131
    
    
    26,915Accounts
      Payable:General
    
    
    990
    
    
    443Affiliated
      Companies
    
    
    14,405
    
    
    17,905Taxes
      Accrued
    
    
    9,165
    
    
    8,806Interest
      Accrued
    
    
    456
    
    
    911Obligations
      Under Capital Leases
    
    
    285
    
    
    210Rent
      Accrued - Rockport Plant Unit 2
    
    
    23,427
    
    
    4,963Other
    
    
    102
    
    
    73**TOTAL**
    
    
    55,961
    
    
    60,226**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    23,687
    
    
    24,762Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    25,965
    
    
    25,428Deferred
      Investment Tax Credits
    
    
    45,416
    
    
    46,250SFAS
      109 Regulatory Liability, Net
    
    
    12,735
    
    
    12,852Deferred
      Gain on Sale and Leaseback - Rockport Plant Unit 2
    
    
    98,512
    
    
    99,904Obligations
      Under Capital Leases
    
    
    12,137
    
    
    12,264Asset
      Retirement Obligations
    
    
    1,240
    
    
    1,216**TOTAL**
    
    
    219,692
    
    
    222,676Commitments
      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
    
    
    5,734Deferred
      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
    )
    
    91Change
      in Other Noncurrent Liabilities
    
    
    436
    
    
    (156
    )**Changes
      in Components of Working Capital:**Accounts
      Receivable
    
    
    (1,170
    )
    
    7,145Fuel,
      Materials and Supplies
    
    
    5,416
    
    
    (3,687
    )Accounts
      Payable
    
    
    (2,953
    )
    
    (243
    )Taxes
      Accrued
    
    
    359
    
    
    4,539Interest
      Accrued
    
    
    (455
    )
    
    (455
    )Rent
      Accrued - Rockport Plant Unit 2
    
    
    18,464
    
    
    18,464Other
      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
      1New
      Accounting Pronouncements
    
    Note
      2Commitments
      and Contingencies
    
    Note
      5Guarantees
    
    Note
      6Business
      Segments
    
    Note
      9Financing
      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
    
    
    2Texas
      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
    
    
    8Nonoperating
      Income and Expense, Net
    
    
    (11
    )Interest
      Charges
    
    
    6**Total
      Change in Operating Expenses and Other**
    
    
    
    
    
    3Income
      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
    
    
    ASenior
      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**
    
    $
    -
    
    $
    760Cash
      flows from (used for):Operating
      activities
    
    
    (121,316
    )
    
    25,873Investing
      activities
    
    
    3,997
    
    
    4,582Financing
      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
    
    
    2030Installment
      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
    
    
    2005Senior
      Unsecured Note Payable
    
    
    100,000
    
    
    Variable
    
    
    2005Securitization
      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)
    
    
    33Net
      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**
    
    
    2,822Net
      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
    
    $
    7,067Noncurrent
      Assets
    
    
    4,275
    
    
    46
    
    
    4,321**Total
      MTM Derivative Contract Assets**
    
    
    9,226
    
    
    2,162
    
    
    11,388Current
      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 - ExchangeTraded
      Contracts
    
    $
    (609
    )
    $
    234
    
    $
    485
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    110Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    1,185
    
    
    1,006
    
    
    740
    
    
    317
    
    
    -
    
    
    -
    
    
    3,248Prices
      Based on Models and OtherValuation
      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**
    
    $
    657Changes
      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
    
    $
    268,858Sales
      to AEP Affiliates
    
    
    4,964
    
    
    18,130**TOTAL**
    
    
    187,158
    
    
    286,988**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    6,075
    
    
    23,106Fuel
      from Affiliates for Electric Generation
    
    
    23
    
    
    40,199Purchased
      Electricity for Resale
    
    
    15,370
    
    
    10,086Purchased
      Electricity from AEP Affiliates
    
    
    -
    
    
    4,073Other
      Operation
    
    
    65,660
    
    
    75,441Maintenance
    
    
    17,039
    
    
    15,404Depreciation
      and Amortization
    
    
    29,286
    
    
    29,097Taxes
      Other Than Income Taxes
    
    
    22,531
    
    
    22,057Income
      Taxes
    
    
    1,461
    
    
    12,006**TOTAL**
    
    
    157,445
    
    
    231,469**OPERATING
      INCOME**
    
    
    29,713
    
    
    55,519Nonoperating
      Income
    
    
    11,155
    
    
    12,102Nonoperating
      Expenses
    
    
    15,137
    
    
    5,108Nonoperating
      Income Tax Credit
    
    
    2,485
    
    
    20Interest
      Charges
    
    
    27,079
    
    
    33,129**NET
      INCOME**
    
    
    1,137
    
    
    29,404Preferred
      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
    )
    $
    1,209,049Common
      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
    )
    $
    1,268,643Preferred
      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
    
    $
    788,371Distribution
    
    
    1,443,548
    
    
    1,433,380General
    
    
    219,463
    
    
    220,435Construction
      Work in Progress
    
    
    53,481
    
    
    50,612**Total**
    
    
    2,508,021
    
    
    2,492,798Accumulated
      Depreciation and Amortization
    
    
    729,655
    
    
    725,225**TOTAL
      - NET**
    
    
    1,778,366
    
    
    1,767,573**OTHER
      PROPERTY AND INVESTMENTS**Nonutility
      Property, Net
    
    
    2,360
    
    
    1,577Bond
      Defeasance Funds
    
    
    21,642
    
    
    22,110**TOTAL**
    
    
    24,002
    
    
    23,687**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    973
    
    
    -Other
      Cash Deposits
    
    
    103,601
    
    
    135,132Accounts
      Receivable:Customers
    
    
    156,320
    
    
    157,431Affiliated
      Companies
    
    
    12,168
    
    
    67,860Accrued
      Unbilled Revenues
    
    
    23,327
    
    
    21,589Allowance
      for Uncollectible Accounts
    
    
    (688
    )
    
    (3,493
    )Materials
      and Supplies
    
    
    12,240
    
    
    12,288Risk
      Management Assets
    
    
    7,067
    
    
    14,048Margin
      Deposits
    
    
    2,778
    
    
    1,891Prepayments
      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
    
    
    15,236Wholesale
      Capacity Auction True-Up
    
    
    574,027
    
    
    559,973Unamortized
      Loss on Reacquired Debt
    
    
    11,576
    
    
    11,842Designated
      for Securitization
    
    
    1,345,935
    
    
    1,361,299Deferred
      Debt - Restructuring
    
    
    11,368
    
    
    11,596Other
    
    
    95,921
    
    
    102,032Securitized
      Transition Assets
    
    
    632,000
    
    
    642,384Long-term
      Risk Management Assets
    
    
    4,321
    
    
    9,508Prepaid
      Pension Obligations
    
    
    109,995
    
    
    109,628Deferred
      Property Taxes
    
    
    29,820
    
    
    -Deferred
      Charges
    
    
    33,951
    
    
    36,986**TOTAL**
    
    
    2,867,476
    
    
    2,860,484Assets
      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 sharesOutstanding
      - 2,211,678 shares
    
    $
    55,292
    
    $
    55,292Paid-in
      Capital
    
    
    132,606
    
    
    132,606Retained
      Earnings
    
    
    1,085,981
    
    
    1,084,904Accumulated
      Other Comprehensive Income (Loss)
    
    
    (8,495
    )
    
    (4,159
    )**Total
      Common Shareholder’s Equity**
    
    
    1,265,384
    
    
    1,268,643Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    5,940
    
    
    5,940**Total
      Shareholders’ Equity**
    
    
    1,271,324
    
    
    1,274,583Long-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
    
    
    365,742Advances
      from Affiliates
    
    
    238,693
    
    
    207Accounts
      Payable:General
    
    
    64,384
    
    
    109,688Affiliated
      Companies
    
    
    68,003
    
    
    64,045Customer
      Deposits
    
    
    4,974
    
    
    6,147Taxes
      Accrued
    
    
    66,229
    
    
    184,014Interest
      Accrued
    
    
    19,589
    
    
    41,227Risk
      Management Liabilities
    
    
    10,663
    
    
    8,394Obligations
      Under Capital Leases
    
    
    431
    
    
    412Other
    
    
    17,511
    
    
    20,115**TOTAL**
    
    
    607,474
    
    
    799,991**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    1,253,495
    
    
    1,247,111Long-term
      Risk Management Liabilities
    
    
    2,124
    
    
    4,896Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    103,419
    
    
    102,624Deferred
      Investment Tax Credits
    
    
    106,677
    
    
    107,743Over-recovery
      of Fuel Costs
    
    
    214,426
    
    
    211,526Retail
      Clawback
    
    
    61,384
    
    
    61,384Other
    
    
    74,318
    
    
    76,653Obligations
      Under Capital Leases
    
    
    498
    
    
    468Deferred
      Credits and Other
    
    
    16,525
    
    
    17,276**TOTAL**
    
    
    1,832,866
    
    
    1,829,681Liabilities
      Held for Sale - Texas Generation Plants
    
    
    254,511
    
    
    249,983Commitments
      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
    
    
    29,097Accretion
      Expense
    
    
    4,529
    
    
    4,067Deferred
      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
    )
    
    259Mark-to-Market
      of Risk Management Contracts
    
    
    6,879
    
    
    5,035Pension
      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
    )
    
    1,439Change
      in Other Noncurrent Liabilities
    
    
    6,929
    
    
    (11,037
    )**Changes
      in Components of Working Capital:**Accounts
      Receivable, Net
    
    
    52,260
    
    
    937Fuel,
      Materials and Supplies
    
    
    98
    
    
    499Accounts
      Payable
    
    
    (41,346
    )
    
    (14,259
    )Taxes
      Accrued
    
    
    (117,785
    )
    
    31,652Customer
      Deposits
    
    
    (1,173
    )
    
    1,974Interest
      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
    
    
    24,742Dividends
      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
      1New
      Accounting Pronouncements
    
    Note
      2Rate
      Matters
    
    Note
      3Customer
      Choice and Industry Restructuring
    
    Note
      4Commitments
      and Contingencies
    
    Note
      5Guarantees
    
    Note
      6Dispositions
      and Assets Held for Sale
    
    Note
      7Benefit
      Plans
    
    Note
      8Business
      Segments
    
    Note
      9Financing
      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
    
    
    2Taxes
      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 millionprimarily
      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
    
    
    ASenior
      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)
    
    
    14Net
      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**
    
    
    1,219Net
      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
    
    $
    4,530Noncurrent
      Assets
    
    
    1,848
    
    
    20
    
    
    1,868**Total
      MTM Derivative Contract Assets**
    
    
    3,988
    
    
    2,410
    
    
    6,398Current
      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 - ExchangeTraded
      Contracts
    
    $
    (263
    )
    $
    101
    
    $
    210
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    48Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    512
    
    
    435
    
    
    320
    
    
    137
    
    
    -
    
    
    -
    
    
    1,404Prices
      Based on Models and OtherValuation
      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**
    
    $
    285Changes
      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
    
    $
    88,712Sales
      to AEP Affiliates
    
    
    11,290
    
    
    14,718**TOTAL**
    
    
    83,233
    
    
    103,430**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    12,611
    
    
    7,500Fuel
      from Affiliates for Electric Generation
    
    
    372
    
    
    11,224Purchased
      Electricity for Resale
    
    
    16,338
    
    
    18,023Purchased
      Electricity from AEP Affiliates
    
    
    22
    
    
    3,532Other
      Operation
    
    
    18,561
    
    
    20,381Maintenance
    
    
    4,219
    
    
    4,683Depreciation
      and Amortization
    
    
    10,155
    
    
    9,692Taxes
      Other Than Income Taxes
    
    
    5,705
    
    
    5,104Income
      Taxes
    
    
    3,586
    
    
    5,941**TOTAL**
    
    
    71,569
    
    
    86,080**OPERATING
      INCOME**
    
    
    11,664
    
    
    17,350Nonoperating
      Income
    
    
    36,002
    
    
    13,756Nonoperating
      Expenses
    
    
    35,108
    
    
    10,936Nonoperating
      Income Tax Expense
    
    
    180
    
    
    894Interest
      Charges
    
    
    4,984
    
    
    6,180**NET
      INCOME**
    
    
    7,394
    
    
    13,096Preferred
      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
    )
    $
    238,275Common
      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
    )
    $
    310,421Common
      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
    
    $
    287,212Transmission
    
    
    280,447
    
    
    281,359Distribution
    
    
    479,251
    
    
    474,961General
    
    
    115,774
    
    
    115,174Construction
      Work in Progress
    
    
    21,487
    
    
    23,621**Total**
    
    
    1,185,066
    
    
    1,182,327Accumulated
      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
    
    
    2,308Advances
      to Affiliates
    
    
    52,736
    
    
    51,504Accounts
      Receivable:Customers
    
    
    53,018
    
    
    90,109Affiliated
      Companies
    
    
    25,696
    
    
    21,474Accrued
      Unbilled Revenues
    
    
    2,567
    
    
    3,789Allowance
      for Uncollectible Accounts
    
    
    (30
    )
    
    (787
    )Unbilled
      Construction Costs
    
    
    16,127
    
    
    22,065Fuel
      Inventory
    
    
    5,736
    
    
    3,148Materials
      and Supplies
    
    
    8,389
    
    
    8,273Risk
      Management Assets
    
    
    4,530
    
    
    6,071Margin
      Deposits
    
    
    2,676
    
    
    818Prepayments
      and Other
    
    
    1,256
    
    
    1,053**TOTAL**
    
    
    175,313
    
    
    209,825**DEFERRED
      DEBITS AND OTHER ASSETS**Regulatory
      Assets:Deferred
      Debt - Restructuring
    
    
    5,971
    
    
    6,093Unamortized
      Loss on Reacquired Debt
    
    
    1,805
    
    
    2,147Other
    
    
    3,675
    
    
    3,783Long-term
      Risk Management Assets
    
    
    1,868
    
    
    4,110Prepaid
      Pension Obligations
    
    
    44,917
    
    
    44,911Deferred
      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 sharesOutstanding
      - 5,488,560 shares
    
    $
    137,214
    
    $
    137,214Paid-in
      Capital
    
    
    2,351
    
    
    2,351Retained
      Earnings
    
    
    168,925
    
    
    170,984Accumulated
      Other Comprehensive Income (Loss)
    
    
    (902
    )
    
    (128
    )**Total
      Common Shareholder’s Equity**
    
    
    307,588
    
    
    310,421Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    2,357
    
    
    2,357**Total
      Shareholders’ Equity**
    
    
    309,945
    
    
    312,778Long-term
      Debt - Nonaffiliated
    
    
    276,773
    
    
    276,748**TOTAL**
    
    
    586,718
    
    
    589,526**CURRENT
      LIABILITIES**Long-term
      Debt Due Within One Year - Nonaffiliated
    
    
    37,609
    
    
    37,609Accounts
      Payable:General
    
    
    14,955
    
    
    22,444Affiliated
      Companies
    
    
    53,078
    
    
    52,801Customer
      Deposits
    
    
    594
    
    
    1,020Taxes
      Accrued
    
    
    26,357
    
    
    37,269Interest
      Accrued
    
    
    3,372
    
    
    5,044Risk
      Management Liabilities
    
    
    3,255
    
    
    3,628Obligations
      Under Capital Leases
    
    
    227
    
    
    220Other
    
    
    7,344
    
    
    9,628**TOTAL**
    
    
    146,791
    
    
    169,663**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    139,898
    
    
    138,465Long-term
      Risk Management Liabilities
    
    
    918
    
    
    2,116Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    81,991
    
    
    81,143Deferred
      Investment Tax Credits
    
    
    18,380
    
    
    18,698Over-recovery
      of Fuel Costs
    
    
    5,320
    
    
    3,920Retail
      Clawback
    
    
    13,924
    
    
    13,924Excess
      Earnings
    
    
    13,146
    
    
    13,270SFAS
      109 Regulatory Liability, Net
    
    
    7,824
    
    
    8,500Other
    
    
    1,156
    
    
    1,319Obligations
      Under Capital Leases
    
    
    383
    
    
    314Deferred
      Credits and Other
    
    
    10,902
    
    
    10,671**TOTAL**
    
    
    293,842
    
    
    292,340Commitments
      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
    
    
    9,692Deferred
      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
    
    
    2,096Over/Under
      Fuel Recovery
    
    
    1,400
    
    
    1,500Change
      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
    
    
    6,754Fuel,
      Materials and Supplies
    
    
    (2,704
    )
    
    2,439Accounts
      Payable
    
    
    (7,212
    )
    
    (11,227
    )Taxes
      Accrued
    
    
    (10,912
    )
    
    8,535Customer
      Deposits
    
    
    (426
    )
    
    305Interest
      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
    
    
    -
    
    
    581Proceeds
      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
    )
    
    21,603Dividends
      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
      1New
      Accounting Pronouncements
    
    Note
      2Rate
      Matters
    
    Note
      3Customer
      Choice and Industry Restructuring
    
    Note
      4Commitments
      and Contingencies
    
    Note
      5Guarantees
    
    Note
      6Benefit
      Plans
    
    Note
      8Business
      Segments
    
    Note
      9Financing
      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
    
    
    15Transmission
      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 2004primarily
      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
    
    $
    4,561Cash
      flows from (used for):Operating
      activities
    
    
    94,570
    
    
    180,602Investing
      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)
    
    
    305Net
      Option Premiums Paid/(Received) (c)
    
    
    -Change
      in Fair Value Due to Valuation Methodology Changes
    
    
    -Changes
      in Fair Value of Risk Management Contracts (d)
    
    
    15,325Changes
      in Fair Value of Risk Management Contracts Allocated to Regulated
      Jurisdictions (e)
    
    
    4,596**Total
      MTM Risk Management Contract Net Assets**
    
    
    65,318Net
      Cash Flowand
      Fair ValueHedge
      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
    
    $
    -
    
    $
    126,924Noncurrent
      Assets
    
    
    144,582
    
    
    719
    
    
    -
    
    
    145,301**Total
      MTM Derivative Contract Assets**
    
    
    265,534
    
    
    6,691
    
    
    -
    
    
    272,225Current
      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 Flowand
      Fair ValueHedges.(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 - ExchangeTraded
      Contracts
    
    $
    (9,621
    )
    $
    3,704
    
    $
    7,671
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    1,754Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    18,437
    
    
    19,928
    
    
    13,827
    
    
    6,359
    
    
    -
    
    
    -
    
    
    58,551Prices
      Based on Models and OtherValuation
      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 NetIncome
      (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
    
    $
    473,225Sales
      to AEP Affiliates
    
    
    52,938
    
    
    53,882**TOTAL**
    
    
    557,079
    
    
    527,107**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    113,381
    
    
    110,711Purchased
      Electricity for Resale
    
    
    28,233
    
    
    16,644Purchased
      Electricity from AEP Affiliates
    
    
    126,963
    
    
    90,487Other
      Operation
    
    
    71,008
    
    
    68,742Maintenance
    
    
    47,190
    
    
    41,320Depreciation
      and Amortization
    
    
    49,959
    
    
    47,913Taxes
      Other Than Income Taxes
    
    
    24,039
    
    
    23,453Income
      Taxes
    
    
    26,242
    
    
    40,440**TOTAL**
    
    
    487,015
    
    
    439,710**OPERATING
      INCOME**
    
    
    70,064
    
    
    87,397Nonoperating
      Income
    
    
    3,487
    
    
    5,547Nonoperating
      Expenses
    
    
    4,563
    
    
    2,533Nonoperating
      Income Tax Credit
    
    
    1,883
    
    
    362Interest
      Charges
    
    
    24,199
    
    
    25,437**NET
      INCOME**
    
    
    46,672
    
    
    65,336Preferred
      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
    )
    $
    1,336,987Common
      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
    )
    $
    1,409,718Capital
      Contribution from Parent
    
    
    
    
    
    100,000
    
    
    
    
    
    
    
    
    100,000Preferred
      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
    
    $
    2,502,273Transmission
    
    
    1,257,336
    
    
    1,255,390Distribution
    
    
    2,088,544
    
    
    2,070,377General
    
    
    294,211
    
    
    302,474Construction
      Work in Progress
    
    
    473,066
    
    
    399,116**Total**
    
    
    6,638,296
    
    
    6,529,630Accumulated
      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
    
    
    20,378Other
      Investments
    
    
    13,029
    
    
    18,775**TOTAL**
    
    
    33,863
    
    
    39,153**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    1,213
    
    
    536Other
      Cash Deposits
    
    
    14,995
    
    
    1,133Advance
      to Affiliates
    
    
    29,054
    
    
    -Accounts
      Receivable:Customers
    
    
    151,080
    
    
    126,422Affiliated
      Companies
    
    
    126,573
    
    
    140,950Accrued
      Unbilled Revenues
    
    
    34,147
    
    
    51,427Miscellaneous
    
    
    1,311
    
    
    1,264Allowance
      for Uncollectible Accounts
    
    
    (1,722
    )
    
    (5,561
    )Risk
      Management Assets
    
    
    126,924
    
    
    81,811Fuel
    
    
    52,058
    
    
    45,756Materials
      and Supplies
    
    
    45,106
    
    
    45,644Margin
      Deposits
    
    
    15,800
    
    
    8,329Prepayments
      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
    
    
    343,415Transition
      Regulatory Assets
    
    
    24,406
    
    
    25,467Unamortized
      Loss on Reacquired Debt
    
    
    17,356
    
    
    18,157Other
    
    
    52,448
    
    
    36,368Long-term
      Risk Management Assets
    
    
    145,301
    
    
    81,245Emission
      Allowances
    
    
    43,530
    
    
    38,931Deferred
      Property Taxes
    
    
    40,423
    
    
    37,071Deferred
      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 EquityCommon
      Stock - No par value:Authorized
      - 30,000,000 sharesOutstanding
      - 13,499,500 shares
    
    $
    260,458
    
    $
    260,458Paid-in
      Capital
    
    
    822,911
    
    
    722,314Retained
      Earnings
    
    
    554,493
    
    
    508,618Accumulated
      Other Comprehensive Income (Loss)
    
    
    (89,382
    )
    
    (81,672
    )**Total
      Common Shareholder’s Equity**
    
    
    1,548,480
    
    
    1,409,718Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    17,784
    
    
    17,784**Total
      Shareholders’ Equity**
    
    
    1,566,264
    
    
    1,427,502Long-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
    
    
    530,010Advances
      from Affiliates
    
    
    -
    
    
    211,060Accounts
      Payable:General
    
    
    176,933
    
    
    130,710Affiliated
      Companies
    
    
    71,712
    
    
    76,314Risk
      Management Liabilities
    
    
    141,701
    
    
    89,136Taxes
      Accrued
    
    
    69,088
    
    
    90,404Interest
      Accrued
    
    
    38,041
    
    
    21,076Customer
      Deposits
    
    
    56,379
    
    
    42,822Obligations
      Under Capital Leases
    
    
    6,577
    
    
    6,742Other
    
    
    50,191
    
    
    56,645**TOTAL**
    
    
    1,240,632
    
    
    1,254,919**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    858,067
    
    
    852,536Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    92,337
    
    
    95,763Over-recovery
      of Fuel Cost
    
    
    61,163
    
    
    57,843Deferred
      Investment Tax Credits
    
    
    29,248
    
    
    30,382Unrealized
      Gain on Forward Commitments
    
    
    35,685
    
    
    23,270Employee
      Benefits and Pension Obligations
    
    
    110,725
    
    
    130,530Long-term
      Risk Management Liabilities
    
    
    104,320
    
    
    57,349Asset
      Retirement Obligations
    
    
    25,101
    
    
    24,626Obligations
      Under Capital Leases
    
    
    12,000
    
    
    13,136Deferred
      Credits
    
    
    16,814
    
    
    17,474**TOTAL**
    
    
    1,345,460
    
    
    1,302,909Commitments
      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
    
    
    47,913Accretion
      Expense
    
    
    474
    
    
    425Deferred
      Income Taxes
    
    
    9,445
    
    
    14,742Deferred
      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
    
    
    2,499Change
      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
    
    
    55,191Fuel,
      Materials and Supplies
    
    
    (5,764
    )
    
    (14,507
    )Accounts
      Payable
    
    
    41,621
    
    
    (25,777
    )Taxes
      Accrued
    
    
    (21,316
    )
    
    26,910Customer
      Deposits
    
    
    13,557
    
    
    10,984Interest
      Accrued
    
    
    16,965
    
    
    17,869Other
      Current Assets
    
    
    (7,918
    )
    
    3,748Other
      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
    )
    
    40,559Proceeds
      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
      1New
      Accounting Pronouncements
    
    Note
      2Rate
      Matters
    
    Note
      3Commitments
      and Contingencies
    
    Note
      5Guarantees
    
    Note
      6Benefit
      Plans
    
    Note
      8Business
      Segments
    
    Note
      9Financing
      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
    
    
    1Other
      Revenues
    
    
    (2
    )**Total
      Change in Gross Margin**
    
    
    
    
    
    (12
    )**Changes
      in Operating Expenses and Other:**Other
      Operation and Maintenance
    
    
    10Depreciation
      and Amortization
    
    
    (1
    )Taxes
      Other Than Income Taxes
    
    
    (1
    )Nonoperating
      Income and Expenses, Net
    
    
    3**Total
      Change in Operating Expenses and Other**
    
    
    
    
    
    11Income
      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)
    
    
    268Net
      Option Premiums Paid/(Received) (c)
    
    
    -Change
      in Fair Value Due to Valuation Methodology Changes
    
    
    -Changes
      in Fair Value of Risk Management Contracts (d)
    
    
    8,528Changes
      in Fair Value of Risk Management Contracts Allocated to Regulated
      Jurisdictions (e)
    
    
    -**Total
      MTM Risk Management Contract Net Assets**
    
    
    33,423Net
      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
    
    $
    -
    
    $
    64,830Noncurrent
      Assets
    
    
    73,988
    
    
    368
    
    
    -
    
    
    74,356**Total
      MTM Derivative Contract Assets**
    
    
    135,883
    
    
    3,303
    
    
    -
    
    
    139,186Current
      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 - ExchangeTraded
      Contracts
    
    $
    (4,923
    )
    $
    1,895
    
    $
    3,925
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    897Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    9,435
    
    
    10,197
    
    
    7,076
    
    
    3,254
    
    
    -
    
    
    -
    
    
    29,962Prices
      Based on Models and OtherValuation
      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**
    
    $
    1,393Changes
      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
    
    $
    344,078Sales
      to AEP Affiliates
    
    
    24,093
    
    
    18,619**TOTAL**
    
    
    364,249
    
    
    362,697**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    61,352
    
    
    41,637Fuel
      From Affiliates for Electric Generation
    
    
    -
    
    
    8,848Purchased
      Electricity for Resale
    
    
    9,203
    
    
    4,681Purchased
      Electricity from AEP Affiliates
    
    
    79,775
    
    
    81,715Other
      Operation
    
    
    48,768
    
    
    57,873Maintenance
    
    
    15,384
    
    
    16,826Depreciation
      and Amortization
    
    
    38,198
    
    
    36,818Taxes
      Other Than Income Taxes
    
    
    36,162
    
    
    35,326Income
      Taxes
    
    
    20,422
    
    
    24,465**TOTAL**
    
    
    309,264
    
    
    308,189**OPERATING
      INCOME**
    
    
    54,985
    
    
    54,508Nonoperating
      Income
    
    
    7,968
    
    
    5,078Nonoperating
      Expenses
    
    
    756
    
    
    734Nonoperating
      Income Tax Expense
    
    
    1,817
    
    
    919Interest
      Charges
    
    
    12,912
    
    
    12,814**NET
      INCOME**
    
    
    47,468
    
    
    45,119Preferred
      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
    )
    $
    897,881Common
      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
    )
    $
    898,650Common
      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
    
    $
    1,658,552Transmission
    
    
    439,747
    
    
    432,714Distribution
    
    
    1,316,498
    
    
    1,300,252General
    
    
    164,314
    
    
    167,985Construction
      Work in Progress
    
    
    127,079
    
    
    131,743**Total**
    
    
    3,712,311
    
    
    3,691,246Accumulated
      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
    
    
    22,322Other
      Investments
    
    
    4,115
    
    
    5,147**TOTAL**
    
    
    25,763
    
    
    27,469**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    671
    
    
    25Other
      Cash Deposits
    
    
    7,158
    
    
    33Advances
      to Affiliates
    
    
    59,416
    
    
    141,550Accounts
      Receivable:Customers
    
    
    46,277
    
    
    41,130Affiliated
      Companies
    
    
    58,598
    
    
    72,854Accrued
      Unbilled Revenues
    
    
    14,510
    
    
    19,580Miscellaneous
    
    
    667
    
    
    1,145Allowance
      for Uncollectible Accounts
    
    
    (76
    )
    
    (674
    )Fuel
    
    
    27,255
    
    
    34,026Materials
      and Supplies
    
    
    36,379
    
    
    37,137Risk
      Management Assets
    
    
    64,830
    
    
    46,631Margin
      Deposits
    
    
    8,229
    
    
    4,848Prepayments
      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
    
    
    16,481Transition
      Regulatory Assets
    
    
    148,285
    
    
    156,676Unamortized
      Loss on Reacquired Debt
    
    
    12,963
    
    
    13,155Other
    
    
    44,147
    
    
    25,691Long-term
      Risk Management Assets
    
    
    74,356
    
    
    46,735Deferred
      Property Taxes
    
    
    48,816
    
    
    64,754Deferred
      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 sharesOutstanding
      - 16,410,426 shares
    
    $
    41,026
    
    $
    41,026Paid-in
      Capital
    
    
    577,669
    
    
    577,415Retained
      Earnings
    
    
    359,739
    
    
    341,025Accumulated
      Other Comprehensive Income (Loss)
    
    
    (66,590
    )
    
    (60,816
    )**Total
      Common Shareholder’s Equity**
    
    
    911,844
    
    
    898,650Preferred
      Stock - No Shares Outstanding
    
    
    -
    
    
    -Authorized
      - 2,500,000 shares at $100 par valueAuthorized
      - 7,000,000 shares at $25 par value**Total
      Shareholder’s Equity**
    
    
    911,844
    
    
    898,650Long-term
      Debt:Nonaffiliated
    
    
    851,691
    
    
    851,626Affiliated
    
    
    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
    
    
    36,000Accounts
      Payable:General
    
    
    52,093
    
    
    63,606Affiliated
      Companies
    
    
    35,523
    
    
    45,745Customer
      Deposits
    
    
    31,063
    
    
    24,890Taxes
      Accrued
    
    
    133,376
    
    
    195,284Interest
      Accrued
    
    
    8,049
    
    
    16,320Risk
      Management Liabilities
    
    
    70,672
    
    
    42,172Obligations
      Under Capital Leases
    
    
    3,590
    
    
    3,854Other
    
    
    16,485
    
    
    24,338**TOTAL**
    
    
    386,851
    
    
    452,209**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    459,333
    
    
    464,545Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    104,889
    
    
    103,104Deferred
      Investment Tax Credits
    
    
    27,272
    
    
    27,933Employee
      Benefits and Pension Obligations
    
    
    49,801
    
    
    62,778Long-term
      Risk Management Liabilities
    
    
    52,868
    
    
    32,731Obligations
      Under Capital Leases
    
    
    8,060
    
    
    8,660Asset
      Retirement Obligations
    
    
    11,799
    
    
    11,585Deferred
      Credits and Other
    
    
    15,469
    
    
    16,075**TOTAL**
    
    
    729,491
    
    
    727,411Commitments
      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
    
    
    36,818Deferred
      Income Taxes
    
    
    (2,613
    )
    
    7,726Deferred
      Investment Tax Credits
    
    
    (661
    )
    
    (752
    )Deferred
      Property Taxes
    
    
    15,938
    
    
    15,011Pension
      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
    
    
    23,091Fuel,
      Materials and Supplies
    
    
    7,529
    
    
    (8,556
    )Accounts
      Payable
    
    
    (21,735
    )
    
    (10,668
    )Taxes
      Accrued
    
    
    (61,908
    )
    
    (7,718
    )Customer
      Deposits
    
    
    6,173
    
    
    6,047Interest
      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
    )
    
    7Proceeds
      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
      1New
      Accounting Pronouncements
    
    Note
      2Rate
      Matters
    
    Note
      3Customer
      Choice and Industry Restructuring
    
    Note
      4Commitments
      and Contingencies
    
    Note
      5Guarantees
    
    Note
      6Benefit
      Plans
    
    Note
      8Business
      Segments
    
    Note
      9Financing
      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
    
    
    5Transmission
      Revenues
    
    
    (7
    )Off-system
      Sales
    
    
    2Other
      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
    
    $
    3,899Cash
      flows from (used for):Operating
      activities
    
    
    42,077
    
    
    181,789Investing
      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**
    
    
    37,371Net
      Cash Flowand
      Fair ValueHedge
      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 2005where
      we entered into the contractprior
      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 Flowand
      Fair ValueHedge
      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
    
    $
    -
    
    $
    72,489Noncurrent
      Assets
    
    
    82,728
    
    
    412
    
    
    -
    
    
    83,140**Total
      MTM Derivative Contract Assets**
    
    
    151,935
    
    
    3,694
    
    
    -
    
    
    155,629Current
      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 - ExchangeTraded
      Contracts
    
    $
    (5,505
    )
    $
    2,119
    
    $
    4,389
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    1,003Prices
      Provided by Other ExternalSources
      - OTC Broker
      Quotes (a)
    
    
    10,549
    
    
    11,402
    
    
    7,912
    
    
    3,638
    
    
    -
    
    
    -
    
    
    33,501Prices
      Based on Models and OtherValuation
      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 NetIncome
      (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
    
    $
    353,822Sales
      to AEP Affiliates
    
    
    80,551
    
    
    57,645**TOTAL**
    
    
    442,143
    
    
    411,467**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    77,824
    
    
    64,041Purchased
      Electricity for Resale
    
    
    11,272
    
    
    6,363Purchased
      Electricity from AEP Affiliates
    
    
    74,009
    
    
    63,128Other
      Operation
    
    
    90,976
    
    
    100,850Maintenance
    
    
    54,322
    
    
    38,042Depreciation
      and Amortization
    
    
    42,745
    
    
    42,715Taxes
      Other Than Income Taxes
    
    
    17,507
    
    
    15,216Income
      Taxes
    
    
    19,934
    
    
    24,299**TOTAL**
    
    
    388,589
    
    
    354,654**OPERATING
      INCOME**
    
    
    53,554
    
    
    56,813Nonoperating
      Income
    
    
    17,497
    
    
    20,588Nonoperating
      Expenses
    
    
    16,013
    
    
    14,851Nonoperating
      Income Tax Expense (Credit)
    
    
    (237
    )
    
    1,613Interest
      Charges
    
    
    15,606
    
    
    17,929**NET
      INCOME**
    
    
    39,669
    
    
    43,008Preferred
      Stock Dividend Requirements including CapitalStock
      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
    )
    $
    1,078,047Common
      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
    )
    $
    1,091,498Common
      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
    
    $
    3,122,883Transmission
    
    
    1,008,687
    
    
    1,009,551Distribution
    
    
    1,005,142
    
    
    990,826General
      (including nuclear fuel)
    
    
    278,890
    
    
    275,622Construction
      Work in Progress
    
    
    183,623
    
    
    163,515**Total**
    
    
    5,600,030
    
    
    5,562,397Accumulated
      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
    
    
    1,053,439Nonutility
      Property, Net
    
    
    49,731
    
    
    50,440Other
      Investments
    
    
    13,251
    
    
    21,848**TOTAL**
    
    
    1,142,908
    
    
    1,125,727**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    535
    
    
    465Other
      Cash Deposits
    
    
    8,005
    
    
    46Advances
      to Affiliates
    
    
    -
    
    
    5,093Accounts
      Receivable:Customers
    
    
    61,822
    
    
    62,608Affiliated
      Companies
    
    
    101,537
    
    
    124,134Miscellaneous
    
    
    4,346
    
    
    4,339Allowance
      for Uncollectible Accounts
    
    
    (76
    )
    
    (187
    )Fuel
    
    
    21,219
    
    
    27,218Materials
      and Supplies
    
    
    104,886
    
    
    103,342Risk
      Management Assets
    
    
    72,489
    
    
    52,141Margin
      Deposits
    
    
    9,184
    
    
    5,400Prepayments
      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
    
    
    147,167Incremental
      Nuclear Refueling Outage Expenses, Net
    
    
    38,727
    
    
    44,244Unamortized
      Loss on Reacquired Debt
    
    
    20,699
    
    
    21,039DOE
      Decontamination Fund
    
    
    12,928
    
    
    14,215Other
    
    
    48,426
    
    
    31,015Long-term
      Risk Management Assets
    
    
    83,140
    
    
    52,256Emission
      Allowances
    
    
    28,024
    
    
    27,093Deferred
      Property Taxes
    
    
    31,461
    
    
    22,372Deferred
      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 SharesOutstanding
      - 1,400,000 Shares
    
    $
    56,584
    
    $
    56,584Paid-in
      Capital
    
    
    858,868
    
    
    858,835Retained
      Earnings
    
    
    239,881
    
    
    221,330Accumulated
      Other Comprehensive Income (Loss)
    
    
    (51,564
    )
    
    (45,251
    )**Total
      Common Shareholder’s Equity**
    
    
    1,103,769
    
    
    1,091,498Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    8,084
    
    
    8,084**Total
      Shareholders’ Equity**
    
    
    1,111,853
    
    
    1,099,582Long-term
      Debt
    
    
    1,314,137
    
    
    1,312,843**TOTAL**
    
    
    2,425,990
    
    
    2,412,425**CURRENT
      LIABILITIES**Cumulative
      Preferred Stock Due Within One Year
    
    
    -
    
    
    61,445Advances
      from Affiliates
    
    
    95,967
    
    
    -Accounts
      Payable:General
    
    
    92,019
    
    
    91,472Affiliated
      Companies
    
    
    38,599
    
    
    51,066Customer
      Deposits
    
    
    34,117
    
    
    29,366Taxes
      Accrued
    
    
    76,868
    
    
    123,159Interest
      Accrued
    
    
    22,072
    
    
    12,465Risk
      Management Liabilities
    
    
    79,163
    
    
    47,174Obligations
      Under Capital Leases
    
    
    5,730
    
    
    6,124Other
    
    
    74,372
    
    
    70,237**TOTAL**
    
    
    518,907
    
    
    492,508**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    304,460
    
    
    315,730Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    281,382
    
    
    280,054Deferred
      Investment Tax Credits
    
    
    80,970
    
    
    82,802Excess
      ARO for Nuclear Decommissioning
    
    
    259,825
    
    
    245,175Unrealized
      Gain on Forward Commitments
    
    
    48,972
    
    
    35,534Other
    
    
    30,832
    
    
    33,695Deferred
      Gain on Sale and Leaseback - Rockport Plant Unit 2
    
    
    65,545
    
    
    66,472Long-term
      Risk Management Liabilities
    
    
    59,408
    
    
    36,815Obligations
      Under Capital Leases
    
    
    40,380
    
    
    44,608Asset
      Retirement Obligations
    
    
    723,433
    
    
    711,769Employee
      Benefits and Pension Obligations
    
    
    55,999
    
    
    70,027Deferred
      Credits and Other
    
    
    38,545
    
    
    40,527**TOTAL**
    
    
    1,989,751
    
    
    1,963,208Commitments
      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
    
    
    42,715Accretion
      Expense
    
    
    11,664
    
    
    9,698Amortization,
      net of Deferrals of Incremental NuclearRefueling
      Outage Expenses
    
    
    5,517
    
    
    13,179Deferred
      Income Taxes
    
    
    (876
    )
    
    1,895Deferred
      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
    
    
    52,625Fuel,
      Materials and Supplies
    
    
    4,455
    
    
    (7,335
    )Accounts
      Payable
    
    
    (11,920
    )
    
    (29,218
    )Taxes
      Accrued
    
    
    (46,291
    )
    
    37,754Customer
      Deposits
    
    
    4,751
    
    
    8,873Interest
      Accrued
    
    
    9,607
    
    
    5,007Rent
      Accrued - Rockport Plant Unit 2
    
    
    18,464
    
    
    18,464Other
      Current Assets
    
    
    (5,072
    )
    
    1,006Other
      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
      1New
      Accounting Pronouncements
    Note
      2Rate
      Matters
    Note
      3Commitments
      and Contingencies
    Note
      5Guarantees
    Note
      6Benefit
      Plans
    Note
      8Business
      Segments
    Note
      9Financing
      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
    
    
    4Transmission
      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)
    
    
    276Changes
      in Fair Value of Risk Management Contracts Allocated to Regulated
      Jurisdictions (e)
    
    
    2,655**Total
      MTM Risk Management Contract Net Assets**
    
    
    15,544Net
      Cash Flowand
      Fair ValueHedge
      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 2005where
      we entered into the contractprior
      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 Flowand
      Fair ValueHedge
      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
    
    $
    -
    
    $
    30,338Noncurrent
      Assets
    
    
    34,410
    
    
    171
    
    
    -
    
    
    34,581**Total
      MTM Derivative Contract Assets**
    
    
    63,196
    
    
    1,723
    
    
    -
    
    
    64,919Current
      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 - ExchangeTraded
      Contracts
    
    $
    (2,290
    )
    $
    882
    
    $
    1,826
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    418Prices
      Provided by Other ExternalSources
      -
      OTC BrokerQuotes
      (a)
    
    
    4,388
    
    
    4,743
    
    
    3,291
    
    
    1,514
    
    
    -
    
    
    -
    
    
    13,936Prices
      Based on Models and OtherValuation
      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
    
    $
    813Changes
      in Fair Value (a)
    
    
    (1,702
    )
    
    -
    
    
    (1,702
    )Reclassifications
      from AOCI to NetIncome
      (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
    
    $
    107,046Sales
      to AEP Affiliates
    
    
    12,189
    
    
    6,612**TOTAL**
    
    
    127,849
    
    
    113,658**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    27,892
    
    
    20,894Purchased
      Electricity from AEP Affiliates
    
    
    44,863
    
    
    33,306Other
      Operation
    
    
    14,560
    
    
    13,272Maintenance
    
    
    5,916
    
    
    7,325Depreciation
      and Amortization
    
    
    11,152
    
    
    10,859Taxes
      Other Than Income Taxes
    
    
    2,425
    
    
    2,328Income
      Taxes
    
    
    4,008
    
    
    6,460**TOTAL**
    
    
    110,816
    
    
    94,444**OPERATING
      INCOME**
    
    
    17,033
    
    
    19,214Nonoperating
      Income
    
    
    445
    
    
    952Nonoperating
      Expenses
    
    
    171
    
    
    1,313Nonoperating
      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
    )
    $
    317,138Common
      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
    
    $
    462,641Transmission
    
    
    385,912
    
    
    385,667Distribution
    
    
    442,925
    
    
    438,766General
    
    
    58,979
    
    
    57,929Construction
      Work in Progress
    
    
    14,702
    
    
    16,544**Total**
    
    
    1,367,155
    
    
    1,361,547Accumulated
      Depreciation and Amortization
    
    
    406,584
    
    
    398,455**TOTAL
      - NET**
    
    
    960,571
    
    
    963,092**OTHER
      PROPERTY AND INVESTMENTS**Nonutility
      Property, Net
    
    
    5,437
    
    
    5,438Other
      Investments
    
    
    351
    
    
    422**TOTAL**
    
    
    5,788
    
    
    5,860**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    276
    
    
    127Other
      Cash Deposits
    
    
    3,319
    
    
    5Advances
      to Affiliates
    
    
    24,734
    
    
    16,127Accounts
      Receivable:Customers
    
    
    24,674
    
    
    22,130Affiliated
      Companies
    
    
    23,232
    
    
    23,046Accrued
      Unbilled Revenues
    
    
    5,703
    
    
    7,340Miscellaneous
    
    
    109
    
    
    94Allowance
      for Uncollectible Accounts
    
    
    (9
    )
    
    (34
    )Fuel
    
    
    8,111
    
    
    6,551Materials
      and Supplies
    
    
    8,698
    
    
    9,385Risk
      Management Assets
    
    
    30,338
    
    
    19,845Margin
      Deposits
    
    
    3,760
    
    
    1,960Prepayments
      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
    
    
    103,849Other
    
    
    22,875
    
    
    14,558Long-term
      Risk Management Assets
    
    
    34,581
    
    
    19,067Emission
      Allowances
    
    
    10,714
    
    
    9,666Deferred
      Property Taxes
    
    
    5,408
    
    
    7,036Deferred
      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 sharesOutstanding
      - 1,009,000 shares
    
    $
    50,450
    
    $
    50,450Paid-in
      Capital
    
    
    208,750
    
    
    208,750Retained
      Earnings
    
    
    80,440
    
    
    70,555Accumulated
      Other Comprehensive Income (Loss)
    
    
    (11,402
    )
    
    (8,775
    )**Total
      Common Shareholder’s Equity**
    
    
    328,238
    
    
    320,980Long-term
      Debt:Nonaffiliated
    
    
    427,375
    
    
    428,310Affiliated
    
    
    80,000
    
    
    80,000**Total
      Long-term Debt**
    
    
    507,375
    
    
    508,310**TOTAL**
    
    
    835,613
    
    
    829,290**CURRENT
      LIABILITIES**Accounts
      Payable:General
    
    
    23,975
    
    
    20,080Affiliated
      Companies
    
    
    21,075
    
    
    24,899Risk
      Management Liabilities
    
    
    32,868
    
    
    17,205Taxes
      Accrued
    
    
    11,663
    
    
    9,248Interest
      Accrued
    
    
    8,992
    
    
    6,754Customer
      Deposits
    
    
    15,709
    
    
    12,309Obligations
      Under Capital Leases
    
    
    1,458
    
    
    1,561Other
    
    
    8,304
    
    
    9,038**TOTAL**
    
    
    124,044
    
    
    101,094**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    224,214
    
    
    227,536Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    29,214
    
    
    28,232Deferred
      Investment Tax Credits
    
    
    6,430
    
    
    6,722Other
      Regulatory Liabilities
    
    
    22,982
    
    
    15,622Employee
      Benefits and Pension Obligations
    
    
    14,714
    
    
    17,729Long-term
      Risk Management Liabilities
    
    
    25,120
    
    
    13,484Obligations
      Under Capital Leases
    
    
    2,577
    
    
    2,802Deferred
      Credits
    
    
    478
    
    
    736**TOTAL**
    
    
    325,729
    
    
    312,863Commitments
      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
    
    
    10,859Deferred
      Income Taxes
    
    
    988
    
    
    3,442Deferred
      Investment Tax Credits
    
    
    (292
    )
    
    (292
    )Deferred
      Property Taxes
    
    
    1,628
    
    
    1,581Pension
      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
    
    
    -
    
    
    1,051Change
      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
    )
    
    8,202Fuel,
      Materials and Supplies
    
    
    (873
    )
    
    (2,772
    )Accounts
      Payable
    
    
    71
    
    
    3,266Taxes
      Accrued
    
    
    2,415
    
    
    5,027Customer
      Deposits
    
    
    3,400
    
    
    2,564Interest
      Accrued
    
    
    2,238
    
    
    1,970Other
      Current Assets
    
    
    (2,234
    )
    
    798Other
      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
    
    
    -
    
    
    20,000Changes
      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
      1New
      Accounting Pronouncements
    Note
      2Rate
      Matters
    Note
      3Commitments
      and Contingencies
    Note
      5Guarantees
    Note
      6Benefit
      Plans
    Note
      8Business
      Segments
    Note
      9Financing
      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
    
    
    5Depreciation
      and Amortization
    
    
    (2
    )Nonoperating
      Income and Expenses, Net
    
    
    23Interest
      Charges
    
    
    6**Total
      Change in Operating Expenses and Other**
    
    
    
    
    
    32Income
      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
    
    $
    7,233Cash
      flows from (used for):Operating
      activities
    
    
    74,821
    
    
    125,131Investing
      activities
    
    
    (144,208
    )
    
    2,187Financing
      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
    
    2029Installment
      Purchase Contracts
    
    54,500
    
    Variable
    
    2028Installment
      Purchase Contracts
    
    54,500
    
    Variable
    
    2028Installment
      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
    
    2029Installment
      Purchase Contracts
    
    51,000
    
    6.375
    
    2029Installment
      Purchase Contracts
    
    40,000
    
    Variable
    
    2028Installment
      Purchase Contracts
    
    40,000
    
    Variable
    
    2028Installment
      Purchase Contracts
    
    18,000
    
    Variable
    
    2029Installment
      Purchase Contracts
    
    18,000
    
    Variable
    
    2029Notes
      Payable
    
    1,463
    
    6.81
    
    2008Notes
      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)
    
    
    374Net
      Option Premiums Paid/(Received) (c)
    
    
    -Change
      in Fair Value Due to Valuation Methodology Changes
    
    
    -Changes
      in Fair Value of Risk Management Contracts (d)
    
    
    9,814Changes
      in Fair Value of Risk Management Contracts Allocated to Regulated
      Jurisdictions (e)
    
    
    -**Total
      MTM Risk Management Contract Net Assets**
    
    
    46,602Net
      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 2005where
      we entered into the contractprior
      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
    
    $
    -
    
    $
    105,414Noncurrent
      Assets
    
    
    106,219
    
    
    811
    
    
    -
    
    
    107,030**Total
      MTM Derivative Contract Assets**
    
    
    205,330
    
    
    7,114
    
    
    -
    
    
    212,444Current
      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 - ExchangeTraded
      Contracts
    
    $
    (6,874
    )
    $
    2,647
    
    $
    5,481
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    1,254Prices
      Provided by Other ExternalSources
      -  OTC Broker Quotes (a)
    
    
    16,284
    
    
    11,207
    
    
    10,584
    
    
    4,544
    
    
    -
    
    
    -
    
    
    42,619Prices
      Based on Models and OtherValuation
      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
    )
    $
    1,241Changes
      in Fair Value (a)
    
    
    (5,476
    )
    
    -
    
    
    (5,476
    )Reclassifications
      from AOCI to NetIncome
      (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
    
    $
    443,729Sales
      to AEP Affiliates
    
    
    151,839
    
    
    146,488**TOTAL**
    
    
    608,070
    
    
    590,217**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    180,261
    
    
    166,271Purchased
      Electricity for Resale
    
    
    18,762
    
    
    12,183Purchased
      Electricity from AEP Affiliates
    
    
    25,618
    
    
    19,303Other
      Operation
    
    
    73,783
    
    
    91,096Maintenance
    
    
    45,755
    
    
    34,051Depreciation
      and Amortization
    
    
    73,947
    
    
    71,782Taxes
      Other Than Income Taxes
    
    
    47,142
    
    
    47,190Income
      Taxes
    
    
    38,571
    
    
    39,982**TOTAL**
    
    
    503,839
    
    
    481,858**OPERATING
      INCOME**
    
    
    104,231
    
    
    108,359Nonoperating
      Income
    
    
    54,972
    
    
    16,751Carrying
      Costs Income
    
    
    22,037
    
    
    179Nonoperating
      Expenses
    
    
    45,027
    
    
    8,069Nonoperating
      Income Tax Expense
    
    
    10,567
    
    
    5,087Interest
      Charges
    
    
    26,163
    
    
    31,969**NET
      INCOME**
    
    
    99,483
    
    
    80,164Preferred
      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
    )
    $
    1,464,025Common
      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
    )
    $
    1,473,838Common
      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
    
    $
    4,127,284Transmission
    
    
    984,702
    
    
    978,492Distribution
    
    
    1,213,373
    
    
    1,202,550General
    
    
    242,690
    
    
    248,749Construction
      Work in Progress
    
    
    329,393
    
    
    240,957**Total**
    
    
    6,907,589
    
    
    6,798,032Accumulated
      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
    
    
    44,774Other
    
    
    8,901
    
    
    13,409**TOTAL**
    
    
    53,644
    
    
    58,183**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    1,083
    
    
    9,300Other
      Cash Deposits
    
    
    9,986
    
    
    37Advances
      to Affiliates
    
    
    41,407
    
    
    125,971Accounts
      Receivable:Customers
    
    
    112,135
    
    
    109,592Affiliated
      Companies
    
    
    147,532
    
    
    144,175Miscellaneous
    
    
    27,144
    
    
    7,626Allowance
      for Uncollectible Accounts
    
    
    (37
    )
    
    (93
    )Fuel
    
    
    69,506
    
    
    70,309Materials
      and Supplies
    
    
    56,855
    
    
    55,569Emissions
      Allowances
    
    
    48,097
    
    
    95,303Risk
      Management Assets
    
    
    105,414
    
    
    79,541Margin
      Deposits
    
    
    11,926
    
    
    7,056Prepayments
      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
    
    
    169,866Transition
      Regulatory Assets
    
    
    202,908
    
    
    225,273Unamortized
      Loss on Reacquired Debt
    
    
    10,866
    
    
    11,046Other
    
    
    65,433
    
    
    22,189Long-term
      Risk Management Assets
    
    
    107,030
    
    
    66,727Deferred
      Property Taxes
    
    
    54,556
    
    
    70,214Deferred
      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 EquityCommon
      Stock - No par value:Authorized
      - 40,000,000 sharesOutstanding
      - 27,952,473 shares
    
    $
    321,201
    
    $
    321,201Paid-in
      Capital
    
    
    462,485
    
    
    462,485Retained
      Earnings
    
    
    856,216
    
    
    764,416Accumulated
      Other Comprehensive Income (Loss)
    
    
    (82,200
    )
    
    (74,264
    )**Total
      Common Shareholder’s Equity**
    
    
    1,557,702
    
    
    1,473,838Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    16,641
    
    
    16,641**Total
      Shareholders’ Equity**
    
    
    1,574,343
    
    
    1,490,479Long-term
      Debt:Nonaffiliated
    
    
    1,594,364
    
    
    1,598,706Affiliated
    
    
    400,000
    
    
    400,000**Total
      Long-term Debt**
    
    
    1,994,364
    
    
    1,998,706**TOTAL**
    
    
    3,568,707
    
    
    3,489,185Minority
      Interest
    
    
    13,475
    
    
    14,083**CURRENT
      LIABILITIES**Short-term
      Debt - Nonaffiliated
    
    
    18,702
    
    
    23,498Long-term
      Debt Due Within One Year - Nonaffiliated
    
    
    12,354
    
    
    12,354Cumulative
      Preferred Stock Subject to Mandatory Redemption
    
    
    -
    
    
    5,000Accounts
      Payable:General
    
    
    190,301
    
    
    143,247Affiliated
      Companies
    
    
    60,079
    
    
    116,615Customer
      Deposits
    
    
    30,991
    
    
    22,620Taxes
      Accrued
    
    
    159,776
    
    
    233,026Interest
      Accrued
    
    
    23,045
    
    
    39,254Risk
      Management Liabilities
    
    
    113,025
    
    
    70,311Obligations
      Under Capital Leases
    
    
    8,806
    
    
    9,081Other
    
    
    71,539
    
    
    74,977**TOTAL**
    
    
    688,618
    
    
    749,983**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    945,105
    
    
    943,465Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    105,503
    
    
    102,875Deferred
      Investment Tax Credits
    
    
    12,290
    
    
    12,539Long-term
      Risk Management Liabilities
    
    
    78,000
    
    
    46,261Deferred
      Credits
    
    
    43,280
    
    
    24,377Employee
      Benefits and Pension Obligations
    
    
    106,201
    
    
    126,825Obligations
      Under Capital Leases
    
    
    29,867
    
    
    31,652Asset
      Retirement Obligations
    
    
    46,494
    
    
    45,606Other
    
    
    6,015
    
    
    6,414**TOTAL**
    
    
    1,372,755
    
    
    1,340,014Commitments
      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
    
    
    71,782Deferred
      Income Taxes
    
    
    4,092
    
    
    7,701Deferred
      Investment Tax Credits
    
    
    (249
    )
    
    (761
    )Deferred
      Property Taxes
    
    
    15,658
    
    
    14,745Pension
      and Postemployment Benefit Reserves
    
    
    (617
    )
    
    4,160Mark-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
    )
    
    2,743Accounts
      Payable
    
    
    (9,482
    )
    
    (21,674
    )Taxes
      Accrued
    
    
    (73,250
    )
    
    18,336Customer
      Deposits
    
    
    8,371
    
    
    10,280Interest
      Accrued
    
    
    (16,209
    )
    
    (16,934
    )Other
      Current Assets
    
    
    40,237
    
    
    618Other
      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
    )
    
    50,953Proceeds
      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
    )
    
    631Issuance
      of Long-term Debt
    
    
    216,798
    
    
    -Issuance
      of Long-term Debt- Affiliated
    
    
    -
    
    
    200,000Retirement
      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
      1New
      Accounting Pronouncements
    Note
      2Rate
      Matters
    Note
      3Customer
      Choice and Industry Restructuring
    Note
      4Commitments
      and Contingencies
    Note
      5Guarantees
    Note
      6Benefit
      Plans
    Note
      8Business
      Segments
    Note
      9Financing
      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
    
    
    15Depreciation
      and Amortization
    
    
    (1
    )Interest
      Charges
    
    
    2**Total
      Change in Operating Expenses and Other**
    
    
    
    
    
    16Income
      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 2004primarily
      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-
    
    ASenior
      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)
    
    
    115Fair
      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**
    
    
    4,298Net
      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 2005where
      we entered into the contractprior
      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
    
    $
    8,448Noncurrent
      Assets
    
    
    6,510
    
    
    70
    
    
    6,580**Total
      MTM Derivative Contract Assets**
    
    
    14,050
    
    
    978
    
    
    15,028Current
      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 - ExchangeTraded
      Contracts
    
    $
    (927
    )
    $
    357
    
    $
    739
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    169Prices
      Provided by Other ExternalSources
      - OTC BrokerQuotes
      (a)
    
    
    1,804
    
    
    1,532
    
    
    1,127
    
    
    483
    
    
    -
    
    
    -
    
    
    4,946Prices
      Based on Models and OtherValuation
      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
    )
    $
    400Changes
      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
    
    $
    204,043Sales
      to AEP Affiliates
    
    
    2,632
    
    
    3,142**TOTAL**
    
    
    253,000
    
    
    207,185**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    134,171
    
    
    89,085Purchased
      Electricity for Resale
    
    
    14,793
    
    
    9,168Purchased
      Electricity from AEP Affiliates
    
    
    22,845
    
    
    26,899Other
      Operation
    
    
    30,185
    
    
    43,395Maintenance
    
    
    11,359
    
    
    13,122Depreciation
      and Amortization
    
    
    22,619
    
    
    22,176Taxes
      Other Than Income Taxes
    
    
    9,677
    
    
    9,817Income
      Taxes (Credits)
    
    
    (852
    )
    
    (7,333
    )**TOTAL**
    
    
    244,797
    
    
    206,329**OPERATING
      INCOME**
    
    
    8,203
    
    
    856Nonoperating
      Income
    
    
    478
    
    
    244Nonoperating
      Expenses
    
    
    551
    
    
    542Nonoperating
      Income Tax Credit
    
    
    250
    
    
    392Interest
      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
    )
    $
    483,008Common
      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
    
    $
    529,256Common
      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
    
    $
    1,072,022Transmission
    
    
    467,953
    
    
    468,735Distribution
    
    
    1,100,348
    
    
    1,089,187General
    
    
    201,397
    
    
    200,044Construction
      Work in Progress
    
    
    47,129
    
    
    41,028**Total**
    
    
    2,885,032
    
    
    2,871,016Accumulated
      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
    
    
    4,401Other
      Investments
    
    
    -
    
    
    81**TOTAL**
    
    
    4,636
    
    
    4,482**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    642
    
    
    91Other
      Cash Deposits
    
    
    156
    
    
    188Accounts
      Receivable:Customers
    
    
    31,319
    
    
    34,002Affiliated
      Companies
    
    
    31,288
    
    
    46,399Miscellaneous
    
    
    8,747
    
    
    6,984Allowance
      for Uncollectible Accounts
    
    
    -
    
    
    (76
    )Fuel
      Inventory
    
    
    14,674
    
    
    14,268Materials
      and Supplies
    
    
    37,950
    
    
    35,485Risk
      Management Assets
    
    
    8,448
    
    
    21,388Regulatory
      Asset for Under-Recovered Fuel Costs
    
    
    -
    
    
    366Margin
      Deposits
    
    
    1,388
    
    
    2,881Prepayments
      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
    
    
    14,705Other
    
    
    16,401
    
    
    17,246Long-term
      Risk Management Assets
    
    
    6,580
    
    
    14,477Prepaid
      Pension Obligations
    
    
    82,466
    
    
    82,419Deferred
      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 sharesIssued
      - 10,482,000 sharesOutstanding
      - 9,013,000 shares
    
    $
    157,230
    
    $
    157,230Paid-in
      Capital
    
    
    230,016
    
    
    230,016Retained
      Earnings
    
    
    133,887
    
    
    141,935Accumulated
      Other Comprehensive Income (Loss)
    
    
    (918
    )
    
    75**Total
      Common Shareholder’s Equity**
    
    
    520,215
    
    
    529,256Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    5,262
    
    
    5,262**Total
      Shareholders’ Equity**
    
    
    525,477
    
    
    534,518Long-term
      Debt:Nonaffiliated
    
    
    446,121
    
    
    446,092Affiliated
    
    
    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
    
    
    50,000Advances
      from Affiliates
    
    
    39,588
    
    
    55,002Accounts
      Payable:General
    
    
    66,278
    
    
    71,442Affiliated
      Companies
    
    
    53,755
    
    
    58,632Customer
      Deposits
    
    
    33,867
    
    
    33,757Taxes
      Accrued
    
    
    33,817
    
    
    18,835Interest
      Accrued
    
    
    2,725
    
    
    4,023Risk
      Management Liabilities
    
    
    8,408
    
    
    13,705Regulatory
      Liability for Over-Recovered Fuel Costs
    
    
    40,529
    
    
    -Obligations
      Under Capital Leases
    
    
    603
    
    
    537Other
    
    
    18,449
    
    
    30,477**TOTAL**
    
    
    348,019
    
    
    336,410**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    386,293
    
    
    384,090Long-term
      Risk Management Liabilities
    
    
    3,235
    
    
    7,455Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    225,316
    
    
    220,298Deferred
      Investment Tax Credits
    
    
    28,172
    
    
    28,620SFAS
      109 Regulatory Liability, Net
    
    
    21,351
    
    
    21,963Unrealized
      Gain on Forward Commitments
    
    
    7,339
    
    
    19,676Obligations
      Under Capital Leases
    
    
    1,086
    
    
    747Deferred
      Credits and Other
    
    
    17,222
    
    
    18,949**TOTAL**
    
    
    690,014
    
    
    701,798Commitments
      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
    
    
    22,176Deferred
      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
    
    
    10,029Fuel
      Recovery
    
    
    40,895
    
    
    4,398Change
      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
    
    
    4,054Fuel,
      Materials and Supplies
    
    
    (2,871
    )
    
    635Accounts
      Payable
    
    
    (10,041
    )
    
    (7,740
    )Taxes
      Accrued
    
    
    14,982
    
    
    17,424Customer
      Deposits
    
    
    110
    
    
    2,357Interest
      Accrued
    
    
    (1,298
    )
    
    32Other
      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
    
    
    3,688Proceeds
      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
    )
    
    14,778Dividends
      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
      1New
      Accounting Pronouncements
    Note
      2Rate
      Matters
    Note
      3Commitments
      and Contingencies
    Note
      5Guarantees
    Note
      6Benefit
      Plans
    Note
      8Business
      Segments
    Note
      9Financing
      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*
    
    
    3Off-system
      Sales
    
    
    (1
    )Other
      Revenues
    
    
    1**Total
      Change in Gross Margin**
    
    
    
    
    
    3**Changes
      in Operating Expenses and Other:**Other
      Operation and Maintenance
    
    
    5Depreciation
      and Amortization
    
    
    (1
    )Taxes
      Other Than Income Taxes
    
    
    1Interest
      Charges
    
    
    3**Total
      Change in Operating Expenses and Other:**
    
    
    
    
    
    8Income
      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 2004primarily
      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-
    
    ASenior
      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
    
    $
    5,676Cash
      flows from (used for):Operating
      activities
    
    
    53,866
    
    
    16,892Investing
      activities
    
    
    (33,260
    )
    
    (72,298
    )Financing
      activities
    
    
    (15,941
    )
    
    56,959Net
      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
    
    2011Note
      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)
    
    
    21Net
      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**
    
    
    5,108Net
      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 2005where
      we entered into the contractprior
      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
    
    $
    9,452Noncurrent
      Assets
    
    
    7,756
    
    
    82
    
    
    7,838**Total
      MTM Derivative Contract Assets**
    
    
    16,759
    
    
    531
    
    
    17,290Current
      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 - ExchangeTraded
      Contracts
    
    $
    (1,102
    )
    $
    424
    
    $
    878
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    200Prices
      Provided by Other ExternalSources
      -
      OTC Broker Quotes (a)
    
    
    2,145
    
    
    1,821
    
    
    1,339
    
    
    574
    
    
    -
    
    
    -
    
    
    5,879Prices
      Based on Models and OtherValuation
      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 NetIncome
      (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
    
    $
    213,949Sales
      to AEP Affiliates
    
    
    17,122
    
    
    22,211**TOTAL**
    
    
    246,996
    
    
    236,160**OPERATING
      EXPENSES**Fuel
      for Electric Generation
    
    
    90,110
    
    
    88,823Purchased
      Electricity for Resale
    
    
    13,380
    
    
    5,934Purchased
      Electricity from AEP Affiliates
    
    
    5,864
    
    
    7,307Other
      Operation
    
    
    44,449
    
    
    50,268Maintenance
    
    
    15,715
    
    
    15,648Depreciation
      and Amortization
    
    
    32,393
    
    
    31,285Taxes
      Other Than Income Taxes
    
    
    15,663
    
    
    16,567Income
      Taxes
    
    
    4,596
    
    
    131**TOTAL**
    
    
    222,170
    
    
    215,963**OPERATING
      INCOME**
    
    
    24,826
    
    
    20,197Nonoperating
      Income
    
    
    1,319
    
    
    1,403Nonoperating
      Expenses
    
    
    474
    
    
    611Nonoperating
      Income Tax Credit
    
    
    200
    
    
    356Interest
      Charges
    
    
    12,780
    
    
    15,443Minority
      Interest
    
    
    (886
    )
    
    (881
    )**NET
      INCOME**
    
    
    12,205
    
    
    5,021Preferred
      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
    )
    $
    696,660Common
      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
    )
    $
    768,618Common
      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
    
    $
    1,663,161Transmission
    
    
    634,206
    
    
    632,964Distribution
    
    
    1,121,224
    
    
    1,114,480General
    
    
    428,751
    
    
    427,910Construction
      Work in Progress
    
    
    59,465
    
    
    48,852**Total**
    
    
    3,912,335
    
    
    3,887,367Accumulated
      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
    
    
    4,049Other
      Investments
    
    
    4,628
    
    
    4,628**TOTAL**
    
    
    8,677
    
    
    8,677**CURRENT
      ASSETS**Cash
      and Cash Equivalents
    
    
    6,973
    
    
    2,308Other
      Cash Deposits
    
    
    6,504
    
    
    6,292Advances
      to Affiliates
    
    
    40,033
    
    
    39,106Accounts
      Receivable:Customers
    
    
    40,117
    
    
    39,042Affiliated
      Companies
    
    
    14,733
    
    
    28,817Miscellaneous
    
    
    5,834
    
    
    5,856Allowance
      for Uncollectible Accounts
    
    
    (5
    )
    
    (45
    )Fuel
      Inventory
    
    
    42,531
    
    
    45,793Materials
      and Supplies
    
    
    36,886
    
    
    36,051Risk
      Management Assets
    
    
    9,452
    
    
    25,379Regulatory
      Asset for Under-Recovered Fuel Costs
    
    
    -
    
    
    4,687Margin
      Deposits
    
    
    1,650
    
    
    3,419Prepayments
      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
    
    
    18,000Unamortized
      Loss on Reacquired Debt
    
    
    20,067
    
    
    20,765Other
    
    
    14,100
    
    
    16,350Long-term
      Risk Management Assets
    
    
    7,838
    
    
    17,179Prepaid
      Pension Obligations
    
    
    80,941
    
    
    81,132Deferred
      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 sharesOutstanding
      - 7,536,640 shares
    
    $
    135,660
    
    $
    135,660Paid-in
      Capital
    
    
    245,003
    
    
    245,003Retained
      Earnings
    
    
    388,783
    
    
    389,135Accumulated
      Other Comprehensive Income (Loss)
    
    
    (2,709
    )
    
    (1,180
    )**Total
      Common Shareholder’s Equity**
    
    
    766,737
    
    
    768,618Cumulative
      Preferred Stock Not Subject to Mandatory Redemption
    
    
    4,700
    
    
    4,700**Total
      Shareholders’ Equity**
    
    
    771,437
    
    
    773,318Long-term
      Debt:Nonaffiliated
    
    
    535,525
    
    
    545,395Affiliated
    
    
    50,000
    
    
    50,000**Total
      Long-term Debt**
    
    
    585,525
    
    
    595,395**TOTAL**
    
    
    1,356,962
    
    
    1,368,713Minority
      Interest
    
    
    1,921
    
    
    1,125**CURRENT
      LIABILITIES**Long-term
      Debt Due Within One Year - Nonaffiliated
    
    
    217,474
    
    
    209,974Accounts
      Payable:General
    
    
    36,154
    
    
    40,001Affiliated
      Companies
    
    
    30,719
    
    
    33,285Customer
      Deposits
    
    
    29,684
    
    
    30,550Taxes
      Accrued
    
    
    61,590
    
    
    45,474Interest
      Accrued
    
    
    11,523
    
    
    12,509Risk
      Management Liabilities
    
    
    12,138
    
    
    18,607Obligations
      Under Capital Leases
    
    
    4,052
    
    
    3,692Regulatory
      Liability for Over-Recovered Fuel Costs
    
    
    13,655
    
    
    9,891Other
    
    
    32,083
    
    
    33,417**TOTAL**
    
    
    449,072
    
    
    437,400**DEFERRED
      CREDITS AND OTHER LIABILITIES**Deferred
      Income Taxes
    
    
    397,563
    
    
    399,756Long-term
      Risk Management Liabilities
    
    
    4,139
    
    
    9,128Reclamation
      Reserve
    
    
    5,761
    
    
    7,624Regulatory
      Liabilities:Asset
      Removal Costs
    
    
    250,637
    
    
    249,892Deferred
      Investment Tax Credits
    
    
    34,466
    
    
    35,539Excess
      Earnings
    
    
    3,167
    
    
    3,167Other
    
    
    11,104
    
    
    21,320Asset
      Retirement Obligations
    
    
    27,518
    
    
    27,361Obligations
      Under Capital Leases
    
    
    30,525
    
    
    30,854Deferred
      Credits and Other
    
    
    54,028
    
    
    54,430**TOTAL**
    
    
    818,908
    
    
    839,071Commitments
      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
    
    
    31,285Deferred
      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
    
    
    11,837Over/Under
      Fuel Recovery
    
    
    8,451
    
    
    9,649Change
      in Other Noncurrent Assets
    
    
    4,760
    
    
    1,175Change
      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
    
    
    6,226Accounts
      Payable
    
    
    (6,413
    )
    
    (13,590
    )Taxes
      Accrued
    
    
    16,116
    
    
    39,682Customer
      Deposits
    
    
    (866
    )
    
    2,132Interest
      Accrued
    
    
    (986
    )
    
    (2,598
    )Other
      Current Assets
    
    
    4,849
    
    
    901Other
      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
    
    
    -
    
    
    52,179Retirement
      of Long-term Debt
    
    
    (2,457
    )
    
    (82,907
    )Changes
      in Advances to/from Affiliates, Net
    
    
    (927
    )
    
    102,744Dividends
      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
      1New
      Accounting Pronouncements
    Note
      2Rate
      Matters
    Note
      3Commitments
      and Contingencies
    Note
      5Guarantees
    Note
      6Benefit
      Plans
    Note
      8Business
      Segments
    Note
      9Financing
      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, TNC2.
    New
      Accounting Pronouncements
    AEGCo,
      APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC3.
    Rate
      Matters
    APCo,
      CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC4.
    Customer
      Choice andIndustry
      Restructuring
    CSPCo,
      OPCo, TCC, TNC5.
    Commitments
      and Contingencies
    AEGCo,
      APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC6.
    Guarantees
    AEGCo,
      APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC7.
    Dispositions
      and Assets Held for Sale
    TCC8.
    Benefit
      Plans
    APCo,
      CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC9.
    Business
      Segments
    AEGCo,
      APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC10.
    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
    )
    
    1,393I&M
    
    
    (10,389
    )
    
    (4,076
    )KPCo
    
    
    (1,814
    )
    
    813OPCo
    
    
    (6,695
    )
    
    1,241PSO
    
    
    (593
    )
    
    400SWEPCo
    
    
    (2,349
    )
    
    (820
    )TCC
    
    
    (3,679
    )
    
    657TNC
    
    
    (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
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    1.2APCo
      (a)
    
    
    24.6
    
    
    0.5
    
    
    -
    
    
    -
    
    
    -
    
    
    25.1CSPCo
      (a)
    
    
    11.6
    
    
    0.2
    
    
    -
    
    
    -
    
    
    -
    
    
    11.8I&M
      (b)
    
    
    711.8
    
    
    11.6
    
    
    -
    
    
    -
    
    
    -
    
    
    723.4OPCo
      (a)
    
    
    45.6
    
    
    0.9
    
    
    -
    
    
    -
    
    
    -
    
    
    46.5SWEPCo
      (c)
    
    
    27.4
    
    
    0.2
    
    
    -
    
    
    (0.1
    )
    
    -
    
    
    27.5TCC
      (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
    
    $
    65,336CSPCo
    
    
    44,705
    
    
    414
    
    
    45,119I&M
    
    
    42,376
    
    
    632
    
    
    43,008KPCo
    
    
    11,490
    
    
    121
    
    
    11,611OPCo
    
    
    79,444
    
    
    720
    
    
    80,164PSO
    
    
    (9,284
    )
    
    281
    
    
    (9,003
    )SWEPCo
    
    
    4,730
    
    
    291
    
    
    5,021TCC
    
    
    29,077
    
    
    327
    
    
    29,404TNC
    
    
    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 SO 2 and
NO x 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
    
    $
    9.7CSPCo
    
    
    4.0I&M
    
    
    7.4KPCo
    
    
    2.2OPCo
    
    
    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
    
    $
    12.1CSPCo
    
    
    4.4
    
    
    6.4I&M
    
    
    4.9
    
    
    7.1KPCo
    
    
    2.0
    
    
    2.8OPCo
    
    
    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
    
    $
    897Net
      Generation-related Regulatory Asset
    
    
    249
    
    
    249Unrefunded
      Excess Earnings
    
    
    (6
    )
    
    (10
    )**Net
      Stranded Generation Costs**
    
    
    1,141
    
    
    1,136Carrying
      Costs on Stranded Generation Plant Costs
    
    
    205
    
    
    225**Net
      Stranded Generation Costs Designated for
      Securitization**
    
    
    1,346
    
    
    1,361Wholesale
      Capacity Auction True-up
    
    
    483
    
    
    483Carrying
      Costs on Wholesale Capacity Auction True-up
    
    
    91
    
    
    77Retail
      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
    
    $
    5CSPCo
    
    
    2I&M
    
    
    3KPCo
    
    
    1OPCo
    
    
    5PSO
    
    
    4SWEPCo
    
    
    4TCC
    
    
    6TNC
    
    
    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**
    
    **December
      31, 2004****Assets:**
    
    **(in
      millions)**Other
      Current Assets
    
    $
    25
    
    $
    24Property,
      Plant and Equipment, Net
    
    
    416
    
    
    413Regulatory
      Assets
    
    
    52
    
    
    48Nuclear
      Decommissioning Trust Fund
    
    
    143
    
    
    143**Total
      Assets Held for Sale - Texas Generation Plants**
    
    $
    636
    
    $
    628**Liabilities:**Regulatory
      Liabilities
    
    $
    1
    
    $
    1Asset
      Retirement Obligations
    
    
    254
    
    
    249**Total
      Liabilities Held for Sale - Texas Generation
    Plants**
    
    $
    255
    
    $
    250
 
 
 **8.**  **BENEFIT
PLANS**
 
 APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP
sponsored U.S. qualified pension plans and nonqualified pension plans. A
substantial majority of employees are covered by either one qualified plan or
both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo,
I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other
postretirement benefit plans sponsored by AEP to provide medical and death
benefits for retired employees in the U.S.
 
 The
following tables provide the components of AEP’s net periodic benefit cost for
the 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
    
    $
    10Interest
      Cost
    
    
    56
    
    
    56
    
    
    27
    
    
    29Expected
      Return on Plan Assets
    
    
    (77
    )
    
    (72
    )
    
    (23
    )
    
    (20
    )Amortization
      of Transition (Asset) Obligation
    
    
    -
    
    
    -
    
    
    7
    
    
    7Amortization
      of Net Actuarial Loss
    
    
    13
    
    
    4
    
    
    7
    
    
    9**Net
      Periodic Benefit Cost (Credit)**
    
    $
    15
    
    $
    10
    
    $
    29
    
    $
    35
 
 The
following table provides the net periodic benefit cost (credit) for the plans by
the following Registrant Subsidiaries for the three months ended March 31, 2005
and 2004:
 
 **Pension
      Plans**
    
    **Other
      Postretirement Benefit Plans****2005**
    
    **2004**
    
    **2005**
    
    **2004****(in
      thousands)**APCo
    
    $
    1,848
    
    $
    318
    
    $
    5,345
    
    $
    6,462CSPCo
    
    
    534
    
    
    (407
    )
    
    2,222
    
    
    2,765I&M
    
    
    2,365
    
    
    1,114
    
    
    3,631
    
    
    4,313KPCo
    
    
    376
    
    
    144
    
    
    603
    
    
    742OPCo
    
    
    1,206
    
    
    (105
    )
    
    3,827
    
    
    4,801PSO
    
    
    72
    
    
    700
    
    
    1,869
    
    
    2,110SWEPCo
    
    
    364
    
    
    901
    
    
    1,837
    
    
    2,101TCC
    
    
    (219
    )
    
    746
    
    
    2,008
    
    
    2,535TNC
    
    
    41
    
    
    338
    
    
    877
    
    
    1,073
 
 
 **9.**  **BUSINESS
SEGMENTS**
 
 All of
AEP’s Registrant Subsidiaries have one reportable segment. The one reportable
segment is a vertically integrated electricity generation, transmission and
distribution business except AEGCo, an electricity generation business. All of
the registrants’ other activities are insignificant. The registrant
subsidiaries’ operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory oversight on the
business process, cost structures and operating results.
 
 
 **10.**  **FINANCING
ACTIVITIES**
 
 Long-term
debt and other securities issued, retired and principal payments made during the
first three months of 2005 were:
 
 **Company**
    
    **Type
      of Debt**
    
    **Principal
      Amount**
    
    **Interest
      Rate**
    
    **Due
      Date****(in
      thousands)**
    
    **(%)****Issuances:**APCo
    
    Senior
      Unsecured Notes
    
    $
    200,000
    
    4.95%
    
    2015OPCo
    
    Installment
      Purchase Contracts
    
    
    54,500
    
    Variable
    
    2029OPCo
    
    Installment
      Purchase Contracts
    
    
    163,500
    
    Variable
    
    2028TCC
    
    Installment
      Purchase Contracts
    
    
    161,700
    
    Variable
    
    2030
 
 **Company**
    
    **Type
      of Debt**
    
    **Principal
      Amount**
    
    **Interest
      Rate**
    
    **Due
      Date****(in
      thousands)**
    
    **(%)****Retirements
      and  Principal**
      **Payments:**APCo
    
    Other
      Debt
    
    $
    2
    
    13.718%
    
    2026OPCo
    
    Installment
      Purchase Contracts
    
    
    102,000
    
    6.375%
    
    2029OPCo
    
    Installment
      Purchase Contracts
    
    
    80,000
    
    Variable
    
    2028OPCo
    
    Installment
      Purchase Contracts
    
    
    36,000
    
    Variable
    
    2029OPCo
    
    Notes
      Payable
    
    
    1,463
    
    6.81%
    
    2008OPCo
    
    Notes
      Payable
    
    
    3,250
    
    6.27%
    
    2009SWEPCo
    
    Notes
      Payable
    
    
    1,707
    
    4.47%
    
    2011SWEPCo
    
    Notes
      Payable
    
    
    750
    
    Variable
    
    2008TCC
    
    Senior
      Unsecured Notes
    
    
    150,000
    
    3.00%
    
    2005TCC
    
    Senior
      Unsecured Notes
    
    
    100,000
    
    Variable
    
    2005TCC
    
    Securitization
      Bonds
    
    
    29,386
    
    3.54%
    
    2005
 
 During
the first quarter of 2005, there were no intercompany issuances and retirements
of debt due to affiliates.
 
 ***Other
Matters***
 
 On
January 3, 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
    
    $
    13I&M
    
    6.250%
    
    192,500
    
    
    19I&M
    
    6.875%
    
    157,500
    
    
    16I&M
    
    6.300%
    
    132,450
    
    
    13OPCo
    
    5.900%
    
    50,000
    
    
    5$
    66
 
 ***Lines
of Credit - AEP System***
 
 The AEP
System uses a corporate borrowing program to meet the short-term borrowing needs
of its 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, the AEP System
also funds, as direct borrowers, the short-term debt requirements of other
subsidiaries that are not participants in either money pool for regulatory or
operational reasons. The AEP System Corporate Borrowing Program operates in
accordance with the terms and conditions outlined by the SEC. AEP has authority
from the SEC through March 31, 2007 for short-term borrowings sufficient to fund
the Utility Money Pool and the Nonutility Money Pool as well as its own
requirements in an amount not to exceed $7.2 billion. The Utility Money Pool
participants’ money pool activity and corresponding SEC authorized limits for
the quarter ended March 31, 2005 are described in the following
table:
 
 **Company**
    
    **Maximum
      Borrowings from Utility Money Pool**
    
    **Maximum
      Loans to Utility Money Pool**
    
    **Average
      Borrowings from Utility Money Pool**
    
    **Average
      Loans to Utility Money Pool**
    
    **Loans
      (Borrowings) to/from Utility Money Pool as of March 31,
      2005**
    
    **SEC
      Authorized Short-Term Borrowing Limit****(in
      thousands)**AEGCo
    
    $
    45,694
    
    $
    -
    
    $
    14,635
    
    $
    -
    
    $
    (7,131
    )
    $
    125,000APCo
    
    
    236,798
    
    
    43,410
    
    
    98,844
    
    
    20,228
    
    
    29,054
    
    
    600,000CSPCo
    
    
    -
    
    
    181,238
    
    
    -
    
    
    140,718
    
    
    59,416
    
    
    350,000I&M
    
    
    96,437
    
    
    11,768
    
    
    29,964
    
    
    5,797
    
    
    (95,967
    )
    
    500,000KPCo
    
    
    -
    
    
    35,779
    
    
    -
    
    
    24,411
    
    
    24,734
    
    
    200,000OPCo
    
    
    -
    
    
    182,495
    
    
    -
    
    
    115,400
    
    
    41,407
    
    
    600,000PSO
    
    
    55,009
    
    
    -
    
    
    21,550
    
    
    -
    
    
    (39,588
    )
    
    300,000SWEPCo
    
    
    -
    
    
    68,537
    
    
    -
    
    
    51,062
    
    
    40,033
    
    
    350,000TCC
    
    
    238,693
    
    
    120,937
    
    
    78,646
    
    
    49,350
    
    
    (238,693
    )
    
    600,000TNC
    
    
    -
    
    
    75,045
    
    
    -
    
    
    48,416
    
    
    52,736
    
    
    250,000
 
 The
maximum and minimum interest rates for funds either borrowed from or loaned to
the Utility Money Pool for the quarter ended March 31, 2005 were 2.96% and
1.63%, respectively. The average interest rates for funds borrowed from and
loaned to the Utility Money Pool for the quarter ended March 31, 2005 are
summarized for all Registrant Subsidiaries in the following table:
 
 **Company**
    
    **Average
      Interest Rate for Funds Borrowed from the Utility Money
      Pool**
    
    **Average
      Interest Rate for Funds Loaned to the Utility Money
      Pool****(in
      percentages)**AEGCo
    
    
    2.00
    
    
    -APCo
    
    
    1.96
    
    
    2.15CSPCo
    
    
    -
    
    
    2.10I&M
    
    
    2.14
    
    
    2.12KPCo
    
    
    -
    
    
    2.15OPCo
    
    
    -
    
    
    2.14PSO
    
    
    2.11
    
    
    -SWEPCo
    
    
    -
    
    
    2.13TCC
    
    
    2.27
    
    
    2.12TNC
    
    
    -
    
    
    2.14
 
 
 
   
   **COMBINED
MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT
SUBSIDIARIES**
 
 The
following is a combined presentation of certain components of the management’s
discussion and analysis of Registrant Subsidiaries. The information in this
section completes the information necessary for management’s discussion and
analysis of financial condition and results of operations and is meant to be
read with (i) Management’s Financial Discussion and Analysis, (ii) financial
statements, and (iii) footnotes of each individual registrant. The Combined
Management’s Discussion and Analysis of Registrants Subsidiaries section of the
2004 Annual Report should be read in conjunction with this report.
 
 **Significant
Factors**
 
 **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.
 
 **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
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.
 
 **Litigation**
 
 Registrant
Subsidiaries continue to be involved in various litigation matters as described
in the “Significant Factors - Litigation” section of the Combined Management’s
Discussion and Analysis of Registrant Subsidiaries in the 2004 Annual Report.
The 2004 Annual Report should be read in conjunction with this report in order
to understand other litigation matters that did not have significant changes in
status since the issuance of the 2004 Annual Report, but may have a material
impact on 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 the current litigation include disclosure related to Coal
Transportation Dispute and Potential Uninsured Losses.
 
 ***Federal
EPA Complaint and Notice of Violation***
 
 See
discussion of New Source Review Litigation under “Environmental
Matters”.
 
 ***Enron
Bankruptcy***
 
 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 Houston
Pipe Line Company (HPL) from Enron. Various HPL related contingencies and
indemnities from Enron remained unsettled at the date of Enron’s
bankruptcy.
 
 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. AEP has
asserted its 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.
 
 The
amounts expensed in prior years in connection with the Enron bankruptcy were
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 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.
 ***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 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 TCC and TNC, 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, have
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 AEP
and its subsidiaries. TCE has appealed the trial court’s decision to the United
States Court of Appeals for the Fifth Circuit.
 
 **Environmental
Matters**
 
 As
discussed in the 2004 Annual Report, there are emerging environmental control
requirements that management expects 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 the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries in the 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 SO*** ***2*** ***,
NO*** **x** ***,
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
SO 2 ,
NO x 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
      SO2and NOxemissions 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 NO x control
program as well as an annual SO 2 control
program. All of the states in which the Registrant
Subsidiaries’ generating facilities are located will be subject to the regional and annual
NO x control
programs and the annual SO 2 control
program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the
annual programs only. Arkansas will be subject to the seasonal NO x control
program only. Oklahoma is not affected by CAIR. In addition, the compliance
deadline for Phase I for the NO x control
program has been accelerated to 2009, and will replace any obligations imposed
by the NO x 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 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.
 
 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. 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 the AEP subsidiaries might have 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 subsidiaries 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.
 
 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 $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.
 
 ***Emergency
Release Reporting***
 
 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.
    
   **CONTROLS
AND PROCEDURES**
 
 During
the first quarter of 2005, management, including the principal executive officer
and principal financial officer of AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the
Registrants’ disclosure controls and procedures. Disclosure controls and
procedures are defined as controls and other procedures of the Registrants that
are designed to ensure that information required to be disclosed by the
Registrants in the reports that they file or submit under the Exchange Act are
recorded, processed, summarized and reported within the time periods specified
in the Commission’s rules and forms. Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by the Registrants in the reports that they file or
submit under the Exchange Act is accumulated and communicated to the
Registrants’ management, including the principal executive and principal
financial officers, or persons performing similar functions, as appropriate to
allow timely decisions regarding required disclosure.
 
 As of
March 31, 2005, these officers concluded that the disclosure controls and
procedures in place are effective and provide reasonable assurance that the
disclosure controls and procedures accomplished their objectives. The
Registrants continually strive to improve their disclosure controls and
procedures to enhance the quality of their financial reporting and to maintain
dynamic systems that change as events warrant.
 
 There was
no change in AEP’s internal control over financial reporting (as such term is
defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first
quarter of 2005 that materially affected, or is reasonably likely to materially
affect, AEP’s internal controls over financial reporting.
    
   **PART
II. OTHER INFORMATION**
 
 **Item
1.** **Legal
Proceedings**
 
 For a
discussion of material legal proceedings, see Note 5, *Commitments
and Contingencies,* incorporated
herein by reference.
 
 **Item
2.** **Unregistered
Sales of Equity Securities and Use of Proceeds**
 
 The
following table provides information about purchases by AEP (or its
publicly-traded subsidiaries) during the quarter ended March 31, 2005 of equity
securities that are registered by AEP (or its publicly-traded subsidiaries)
pursuant to Section 12 of the Exchange Act:
 
 ISSUER
PURCHASES OF EQUITY SECURITIES
 
 **Period**
    
    **Total
      Number**
      **of
      Shares**
      **Purchased
      (a)**
    
    **Average
      Price**
      **Paid
      per Share**
    
    **Total
      Number Of Shares Purchased as Part of Publicly Announced Plans or
      Programs**
    
    **Maximum
      Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased
      Under the Plans or Programs**01/01/05
      - 01/31/05
    
    
    -
    
    $
    -
    
    
    -
    
    $
    -02/01/05
      - 02/28/05
    
    
    -
    
    
    -
    
    
    -
    
    
    (b
    )03/01/05
      - 03/31/05
    
    
    12,500,000
    
    
    34.63
    
    
    12,500,000
    
    
    -**Total**
    
    
    12,500,000
    
    $
    34.63
    
    
    12,500,000
    
    $
    (b
    )
 
 (a)
    The
      repurchase was funded with available cash on hand.(b)
    In
      February 2005, AEP’s board of directors authorized the repurchase of
      outstanding common shares of AEP up to an aggregate purchase price of $500
      million.
 
 On March
9, 2005, AEP announced the repurchase of 12.5 million shares of its outstanding
common stock through an accelerated share repurchase agreement at an initial
price of $34.63 per share, for a total of approximately $433 million. 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 which ends in May 2005.
 
 As of
April 29, 2005, the counterparty to the agreement had repurchased 95.2% of the
shares under the program at an average price per share of approximately $34.12.
Assuming the counterparty repurchased the remaining shares at a price per share
of $35.22, which was the closing price of AEP’s common stock on April 29, 2005,
AEP would receive a payment of approximately $5.7 million from the counterparty
(excluding expenses and related items). The settlement amount can increase or
decrease depending upon the actual price paid for the shares repurchased by the
counterparty under the program. The settlement is expected to occur in May
2005.
 **Item
5.** **Other
Information**
 
 NONE
 
 **Item
6.** **Exhibits**
 
 *AEP*
**
4(a)
- Purchase Agreement dated as of March 8, 2005, between AEP and Merrill Lynch
International.
10(b) -
AEP Retainer Deferral Plan for Non-Employee Directors’ effective January 1,
2005, as amended March 10, 2005(previously
known as AEP Deferred Compensation and Stock Plan for Non-Employee
Directors).
31(a) -
Certification of AEP Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31(c) -
Certification of AEP Chief Financial Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
**
*AEP,
APCo, OPCo*
**
10(a) -
Form of Restricted Stock Unit Agreement furnished to participants of the AEP
System 2000 Long-term Incentive Plan, as amended.
**
*AEP,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC*
**
12 -
Computation of Consolidated Ratio of Earnings to Fixed Charges.
**
*AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC*
**
31(b) -
Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.

31(d) -
Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
**
*AEP,
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC*
**
32(a) -
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code.

32(b) -
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code.
    
   
 
 **SIGNATURE**
 
 
 
 
 Pursuant
to the requirements of the Securities Exchange Act of 1934, each registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized. The signature for each undersigned company shall be deemed to
relate only to matters having reference to such company and any subsidiaries
thereof.
 
 AMERICAN
ELECTRIC POWER COMPANY, INC.
 
 
 
 By: /s/Joseph
M. Buonaiuto
 Joseph M.
Buonaiuto
 Controller
and Chief Accounting Officer
 
 
 
 AEP
GENERATING COMPANY
 AEP TEXAS
CENTRAL COMPANY
 AEP TEXAS
NORTH COMPANY
 APPALACHIAN
POWER COMPANY
 COLUMBUS
SOUTHERN POWER COMPANY
 INDIANA
MICHIGAN POWER COMPANY
 KENTUCKY
POWER COMPANY
 OHIO
POWER COMPANY
 PUBLIC
SERVICE COMPANY OF OKLAHOMA
 SOUTHWESTERN
ELECTRIC POWER COMPANY
 
 
 
 
 By: /s/Joseph
M. Buonaiuto
 Joseph M.
Buonaiuto
 Controller
and Chief Accounting Officer
 
 
 
 Date: May
4, 2005